For immediate release
Nexen Announces Ongoing Execution Success and First Quarter Results
Calgary, Alberta, April 27, 2010 – Nexen Inc. announces continued success executing on its three strategies. On the conventional side of our business, we had a major oil discovery at Appomattox in the Eastern Gulf of Mexico. When we combine this with our recent exploration successes at Golden Eagle in the North Sea, and Owowo, offshore West Africa, we have delivered significant discoveries in all of our core conventional areas. At our Long Lake oil sands project, we are steadily climbing the growth curve, achieving new record bitumen production volumes each month as we increase steam volumes. In the Horn River, we finished drilling our eight-well shale gas program and realized further cost improvements. All of this success is contributing to the visible growth we have coming - Horn River shale gas, Usan in 2012, Golden Eagle in 2014 and then Appomattox, Owowo and future phases of Long Lake. Our 85% weighting to crude oil is driving our industry-leading netbacks resulting in superior returns for every dollar we invest.
Recent highlights include:
| · | First quarter cash flow of $538 million ($1.03/share) |
| · | Quarterly earnings of $185 million ($0.35/share) |
| · | Quarterly production before royalties of 252,000 boe/d (221,000 boe/d after royalties) |
| · | Long Lake bitumen production volumes consistently increasing each month since turnaround as steam volumes grow |
| · | Significant oil discovery at Appomattox in the Gulf of Mexico |
| · | Successfully finished drilling our eight well shale gas program in the Horn River |
| · | Completed sale of European marketing business and substantially completed negotiations for the sale of our North American gas marketing business |
| Three Months Ended | Three Months Ended | |||||||||||
| March 31 | December 31 | |||||||||||
| (Cdn$ millions) | 2010 | 2009 | 2009 | |||||||||
| Production (mboe/d) | ||||||||||||
| Before Royalties | 252 | 252 | 265 | |||||||||
| After Royalties | 221 | 225 | 235 | |||||||||
| Net Sales | 1,501 | 1,048 | 1,550 | |||||||||
Cash Flow from Operations1 | 538 | 557 | 836 | |||||||||
Per Common Share ($/share)1 | 1.03 | 1.07 | 1.60 | |||||||||
| Net Income (Loss) | 185 | 135 | 259 | |||||||||
| Per Common Share ($/share) | 0.35 | 0.26 | 0.50 | |||||||||
Capital Investment2,3 | 568 | 1,516 | 645 | |||||||||
Net Debt4 | 5,057 | 5,737 | 5,551 | |||||||||
1 For reconciliation of this non-GAAP measure, see Cash Flow from Operations on pg. 9.
2 Includes geological and geophysical expenditures.
3 Q1 2009 includes $755 million for the acquisition of an additional 15% interest in Long Lake from our partner.
4 Net debt is defined as long-term debt and short-term borrowings less cash and cash equivalents.
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Financial Results
Quarterly cash flow from operations was $538 million and net income was $185 million. With the increase in WTI, our average realized oil and gas price increased 48% over the same quarter last year to $70/boe. Since 85% of our production is weighted to oil, we continue to benefit from increasing oil prices. Quarterly cash flow was reduced by Long Lake accounting and reported results from marketing.
With consistent and improving performance at Long Lake, we are no longer capitalizing start up results. As a result, we expensed an operating loss in the quarter and expect Long Lake to make positive cash flow contributions later this year as our growth continues.
Marketing’s results for the quarter reflect losses from the impact of softening gas prices on our transportation contracts and on the reported value of our gas inventories. These losses partially offset related gains reported in the previous quarter. We have substantially completed negotiations for the sale of our North American natural gas marketing business and we expect the disposition to close in the third quarter.
Compared to the previous quarter, our production volumes and financial results were impacted by temporary downtime at Buzzard, Ettrick and Syncrude.
Quarterly Production
| Quarterly Production before Royalties | Quarterly Production after Royalties | |||||||||||||||
Crude Oil, NGLs and Natural Gas (mboe/d) | Q1 2010 | Q4 2009 | Q1 2010 | Q4 2009 | ||||||||||||
| North Sea | 112 | 124 | 112 | 124 | ||||||||||||
| Yemen | 43 | 45 | 23 | 26 | ||||||||||||
| Canada – Oil & Gas | 36 | 37 | 31 | 31 | ||||||||||||
| United States | 27 | 24 | 24 | 21 | ||||||||||||
| Canada – Syncrude | 20 | 24 | 18 | 22 | ||||||||||||
| Canada – Bitumen | 12 | 9 | 11 | 9 | ||||||||||||
| Other Countries | 2 | 2 | 2 | 2 | ||||||||||||
| Total | 252 | 265 | 221 | 235 | ||||||||||||
First quarter production volumes averaged 252,000 boe/d (221,000 boe/d after royalties) as volumes were temporarily impacted by downtime at Buzzard, Ettrick and Syncrude. At Buzzard, volumes were lower as repairs were made to the separator unit. Buzzard production averaged 197,000 boe/d gross (85,000 boe/d net to us) for the first quarter compared to typical rates of approximately 210,000 boe/d gross. In the second quarter, further activities are planned to permanently repair the separator unit. This downtime will coincide with our planned two week shutdown to install the topsides of the fourth platform. At Ettrick, production was primarily impacted by commissioning activities and a two week shut-in for rig moves relating to drilling and completion activities in the area. Ettrick production has been restored, is currently produci ng at rates around 20,000 boe/d gross (16,000 boe/d net to us) and continues to ramp up.
At Syncrude, production was lower than the previous quarter as a turnaround of the LC finer originally planned for the second quarter was advanced to January. The turnaround was completed in mid March. A coker turnaround is scheduled at Syncrude in the third quarter.
“We are currently producing approximately 270,000 boe/d but have scheduled downtime later this quarter at Buzzard,” commented Marvin Romanow, Nexen’s President and Chief Executive Officer. “Once this second quarter downtime is behind us, we are well positioned for strong volumes in the second half of the year as we continue to grow new production at Long Lake, Ettrick and in the Horn River.”
Long Lake—Bitumen Volumes Consistently Growing
Since the completion of the turnaround last fall, bitumen volumes have been consistently growing. Long Lake’s gross bitumen production has grown from 14,000 bbls/d in the fourth quarter of 2009 to 19,000 bbls/d in the first quarter of 2010. In March, bitumen production averaged 22,000 bbls/d and we are currently producing approximately 25,000 bbls/d and are seeing production increases from both new wells and from optimization of mature producers. This represents an 80% increase over average pre-turnaround rates.
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The table below shows gross bitumen production volumes since the turnaround.
| Month | Long Lake Monthly Bitumen Volumes Gross (bbls/day) |
| October 2009 | 8,600 |
| November 2009 | 15,200 |
| December 2009 | 16,200 |
| January 2010 | 16,300 |
| February 2010 | 17,700 |
| March 2010 | 21,900 |
| April 2010-MTD | 24,200 |
Production growth reflects significant improvement in steam reliability since the turnaround and steam rates are at all-time highs of about 140,000 bbls/d and increasing. This represents a 100% increase over pre-turnaround rates. As a result, we are injecting more steam into more wells than ever before with 64 well pairs now on production and steam circulating in an additional 15 pairs. These circulating wells will be converted to production over the next few months.
Our all-in steam-to-oil ratio (SOR) is between 5 and 6 but this includes steam to wells that are still in the steam circulation stage and wells early in their growth cycle. As our circulating wells start producing bitumen, we expect to see an increase in bitumen production rates with a corresponding decrease in SOR. The SOR of our producing wells is approximately 5, and includes well pairs recently converted to production that are in the early stages of ramp up. We continue to expect a long term SOR of 3.0 over the life of the project.
“Long Lake is performing well since the turnaround last September. Steam and bitumen production volumes have steadily grown each month and this upward trend continues,” stated Romanow. “As we provide consistent steam to the reservoir, we are focusing on optimizing steam injection and individual well performance. To advance well productivity, we have converted over 50% of our wells from gas lift to electric submersible pumping and expect to have about 80% converted by year end. This offers more flexibility to optimize steam injection and grow bitumen production.”
The upgrader facility is also performing consistently. Since the turnaround, the upgrader has experienced 90% uptime, compared to 50% before and is producing high quality premium synthetic crude (PSCTM). For the quarter, our realized price for Long Lake PSCTM averaged over $81/bbl. The gasification process is working, creating a low-cost fuel source which reduces our need to purchase natural gas for operations and will generate a significant margin advantage over our peers, even at current low gas prices.
Global Exploration—Another Significant Discovery
United States
During the quarter, we made a significant discovery in the Eastern Gulf of Mexico at Appomattox, located in Mississippi Canyon blocks 391 and 392. Drilling activities resulted in an oil discovery with excellent reservoir quality, following an exploration well and two appraisal sidetracks. The discovery well, located in 7,217 feet of water, was drilled to a depth of 25,077 feet true vertical depth and encountered approximately 530 feet gross (425 feet net) true vertical thickness of oil pay. An appraisal sidetrack was drilled to approximately 25,950 feet true vertical depth and encountered approximately 380 feet (360 feet net) true vertical thickness of oil pay. The second sidetrack was undertaken to further delineate the discovery. Well results have exceeded our pre-drill expectations.
Appomattox is the third discovery in the area following earlier discoveries at Shiloh and Vicksburg. Additional appraisal wells for Appomattox are planned for later in the year and we are investigating development options for Appomattox and Vicksburg, located six miles east. We have a 25% interest in Vicksburg and a 20% interest in Appomattox and Shiloh. Shell Offshore Inc. operates all three discoveries.
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"Initial estimates of the Appomattox discovery support development of a regional hub and we are actively appraising results,” commented Romanow. “This is light sweet oil from a reservoir with excellent characteristics leading to strong productivity. The discovery increases our excitement regarding our other exploration prospects in the area, where we have a strong regional land position.”
Elsewhere in the deep-water, we completed drilling an appraisal well at Knotty Head and are currently evaluating results and possible development choices. Drilling operations with our new deep-water rig exceeded expectations. We completed the well in approximately 15% less time than expected and 20% below planned cost. We are continuing our efforts to unitize our lands with adjacent acreage. We are operator of Knotty Head with a 25% working interest. A second deep-water drilling rig is expected to arrive later this year which will allow us to start drilling our other identified prospects.
North Sea
The Golden Eagle area has emerged as a significant development opportunity for us. Our current estimate of recoverable contingent resource is 150 million boe or higher (over 55 million boe, net to us). We are in the process of completing the acquisition of additional land in the area and plan to drill an exploration well here mid-year. Golden Eagle area development supports standalone facilities and is economic with oil prices significantly lower than they are currently. We are assessing development options for the area and will select an appropriate conf iguration prior to sanctioning in 2011. We have a 34% interest in both Golden Eagle and Hobby, a 46% interest in Pink, and operate all three.
West of the Shetland Islands, we are finalizing plans to drill the North Uist prospect. We have a 35% working interest here and expect to drill the well in the second half of 2010. This prospect has a target size much larger than typical North Sea targets. BP is the operator with a 45% working interest.
“We continue to build our strategic advantage in the North Sea,” commented Romanow. “With no near-term decline expected at Buzzard, significant discoveries to develop, strategic land positions and numerous exploration and appraisal wells to be drilled, we expect to advance our leading position with even more growth in the next five to ten years.”
Conventional Development—Usan Development Continues
Offshore West Africa
Development of the Usan field, offshore West Africa, is progressing well with first production expected in 2012. The development includes a Floating Production and Storage Offloading vessel (FPSO) with the ability to process 180,000 bbls/d (36,000 bbls/d net to us) and store up to two million barrels of oil. We have a 20% interest in exploration and development on this block and Total E&P Nigeria Limited is the operator.
We continue to explore offshore West Africa and previously announced a successful exploration well at Owowo in the southern portion of Oil Prospecting License (OPL) 223. Other exploration prospects are under evaluation for drilling.
Horn River Shale Gas—Successfully Finished Drilling Eight-Well Program
We have finished drilling our eight-well program and continue to make significant progress on lowering costs and gaining access to the shale reservoir on our substantial Horn River shale gas position in north-east British Columbia. We plan to complete these wells in the second half of the year with 18 fracs per well. First production is expected before year end, ramping up to 50 mmcf/d.
Substantial cost savings and productivity improvements were realized with this drilling program and our average drilling days per well were under 25 days, down 35% over our previous pad. We currently expect that with an 18 well program we could reduce our all-in costs even further to under $0.6 million per frac.
As previously announced, we estimate our Dilly Creek lands in the Horn River basin contain between 3 and 6 trillion cubic feet (0.5 to 1.0 billion barrels of oil equivalent) of recoverable contingent resource, assuming a 20% recovery factor. Our production results to date, together with those of our competitors, indicate that recovery factors will be higher. Additional production history will determine recovery factors and further appraisal activity is required before we can finalize resource estimates.
“I am pleased with the progress we are making in shale gas,” said Romanow. “We are successfully executing our drilling plans and bringing unit costs down. With a substantial land position and favorable land tenure terms, we are in excellent position to control the pace of development and maximize the value of this resource.”
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Disposition Update
As announced in December 2009, we identified a number of non-core assets for possible disposal, including parts of our marketing business, our heavy oil assets in Western Canada and our interest in the Canexus chemicals business. We are confident that the disposition of these non-core assets will generate over $1 billion in the next 12 to 18 months with timing dependent on market conditions.
We have successfully sold our European gas and power marketing business for $15 million of cash proceeds. We have substantially completed negotiations for the sale of our North American natural gas marketing business subject to finalizing documentation and customary closing conditions. We expect to sign the agreement in the second quarter and close the sale in the third quarter. The sale is expected to be cash neutral and we expect to recognize a non-cash loss on the sale of between $250 to $290 million. This loss primarily relates to the transfer of long-term natural gas physical transportation commitments that are less valuable with increased gas supplies that reduce the need for transportation services. Although volatile on a quarterly basis, we have had great success with our marketing business over the last 10 years generating about $800 million of free cash.
“To maximize shareholder value, assets that are no longer aligned with our main areas of focus will be monetized,” said Romanow. “The sale of parts of our marketing business is almost complete and we have opened data rooms for our heavy oil assets which we expect to sell mid-year. The gains we expect to book from the sale of our heavy oil assets and Canexus will significantly exceed the loss on the closing of the marketing sale.”
Delivering on Execution
We are executing on our strategies with significant success. We have had major discoveries in each of our three key conventional basins—Golden Eagle area in the North Sea, Appomattox in the Eastern Gulf of Mexico and Owowo, offshore West Africa. At Long Lake we are consistently making progress. We are generating more steam than ever before, bitumen volumes are at all time highs and the upgrader is operating reliably producing high quality synthetic crude. In the Horn River, we continue to make significant steps in lowering our costs and we are executing our programs in line with or better than competitors in the area.
“We are generating value and are well positioned for growth,” stated Romanow. “Our industry-leading netbacks are driving superior returns for every dollar we invest. When you combine this with visible growth coming from several identified projects such as Horn River shale gas, Usan in 2012, Golden Eagle two years after that and then Appomattox, Owowo and future phases of Long Lake, the value proposition for Nexen shareholders is significant. In the next few years, we have approximately 70,000 bbls/day of new production coming on as we grow Long Lake and bring Usan on stream.”
Quarterly Dividend
The Board of Directors has declared the regular quarterly dividend of $0.05 per common share payable July 1, 2010, to shareholders of record on June 10, 2010. Shareholders are advised that the dividend is an eligible dividend for Canadian Income Tax purposes.
Nexen Inc. is an independent, Canadian-based global energy company, listed on the Toronto and New York stock exchanges under the symbol NXY. We are focused on three growth strategies: oil sands and unconventional gas in Western Canada and conventional exploration and development primarily in the North Sea, offshore West Africa and deep-water Gulf of Mexico. We add value for shareholders through successful full-cycle oil and gas exploration and development, and leadership in ethics, integrity, governance and environmental stewardship.
Information on our previously announced recoverable contingent shale gas and Golden Eagle area resource were provided in our press releases dated April 22, 2008 and September 3, 2009 respectively. Information with respect to forward-looking statements and cautionary notes is set out below.
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For investor relations inquiries, please contact: Michael J. Harris, CA Vice President, Investor Relations (403) 699-4688 Lavonne Zdunich, CA Manager, Investor Relations (403) 699-5821 Tim Chatten, P.Eng Analyst, Investor Relations (403) 699-4244 801 – 7th Ave SW Calgary, Alberta, Canada T2P 3P7 www.nexeninc.com | For media and general inquiries, please contact: Pierre Alvarez Vice President, Corporate Relations (403) 699-5560 Kevin Reinhart, CA Senior Vice President and CFO (403) 699-5931 |
Conference Call
Marvin Romanow, President and CEO, and Kevin Reinhart, Senior Vice President and CFO, will host a conference call to discuss our first quarter financial and operating results and expectations for the future.
Date: April 27, 2010
Time: 7:00 a.m. Mountain Time (9:00 a.m. Eastern Time)
To listen to the conference call, please call one of the following:
416-695-6616 (Toronto)
800-766-6630 (North American toll-free)
800-4222-8835 (Global toll-free)
A replay of the call will be available for two weeks starting at 9:00 a.m. Mountain Time, by calling 416-695-5800 (Toronto) or 800-408-3053 (toll-free) passcode 2655438 followed by the pound sign.
A live and on demand webcast of the conference call will be available at www.nexeninc.com.
Forward-Looking Statements
Certain statements in this report constitute “forward-looking statements” (within the meaning of the United States Private Securities Litigation Reform Act of 1995) or “forward-looking information” (within the meaning of applicable Canadian securities legislation). Such statements or information (together “forward-looking statements”) are generally identifiable by the forward-looking terminology used such as “anticipate”, “believe”, “intend”, “plan”, “expect”, “estimate”, “budget”, “outlook”, “forecast” or other similar words and include statements relating to or associated with individual wells, regions or projects. Any statements as to possible future crude oil, natural gas or chemicals prices, future production levels, future capital expenditures and their allocation to exploration and development activities, future earnings, future asset acquisitions or dispositions, future sources of funding for our capital program, future debt levels, availability of committed credit facilities, possible commerciality, development plans or capacity expansions, future ability to execute dispositions of assets or businesses, future sources of liquidity, cash flows and their uses, future drilling of new wells, ultimate recoverability of current and long-term assets, ultimate recoverability of reserves or resources, expected finding and development costs, expected operating costs, future cost recovery oil revenues from our Yemen operations, future demand for chemicals products, estimates on a per share basis, future foreign currency exchange rates, future expenditures and future allowances relating to environmental matter s and dates by which certain areas will be developed, come on stream, or reach expected operating capacity and changes in any of the foregoing are forward-looking statements. Statements relating to “reserves” or “resources” are forward-looking statements, as they involve the implied assessment, based on estimates and assumptions that the reserves and resources described exist in the quantities predicted or estimated, and can be profitably produced in the future.
The forward-looking statements are subject to known and unknown risks and uncertainties and other factors which may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such statements. Such factors include, among others: market prices for oil and gas and chemicals products; our ability to explore, develop, produce, upgrade and transport crude oil and natural gas to markets; ultimate effectiveness of design or design modifications to facilities; the results of exploration and development drilling and related activities; volatility in energy trading markets; foreign-currency exchange rates; economic conditions in the countries and regions in which we carry on business; governmental actions including changes to taxes or royalties, changes in environment al and other laws and regulations; renegotiations of contracts; results of
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litigation, arbitration or regulatory proceedings; and political uncertainty, including actions by terrorists, insurgent or other groups, or other armed conflict, including conflict between states. The impact of any one risk, uncertainty or factor on a particular forward-looking statement is not determinable with certainty as these factors are interdependent, and management’s future course of action would depend on our assessment of all information at that time.
Although we believe that the expectations conveyed by the forward-looking statements are reasonable based on information available to us on the date such forward-looking statements were made, no assurances can be given as to future results, levels of activity and achievements. Undue reliance should not be placed on the statements contained herein, which are made as of the date hereof and, except as required by law, Nexen undertakes no obligation to update publicly or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The forward-looking statements contained herein are expressly qualified by this cautionary statement. Readers should also refer to Items 1A and 7A in our 2009 Annual Report on Form 10-K for further discussion of the risk factors.
Cautionary Note to US Investors
In this disclosure, we may refer to “recoverable reserves”, “recoverable resources” and “recoverable contingent resources” which are inherently more uncertain than proved reserves or probable reserves. These terms are not used in our filings with the SEC. Our reserves and related performance measures represent our working interest before royalties, unless otherwise indicated. Please refer to our Annual Report on Form 10-K available from us or the SEC for further reserve disclosure.
Cautionary Note to Canadian Investors
Nexen is an SEC registrant and a voluntary Form 10-K (and related forms) filer. Therefore, our reserves estimates and securities regulatory disclosures follow SEC requirements. In Canada, National Instrument 51-101—Standards of Disclosure for Oil and Gas Activities (NI 51-101) prescribes that Canadian companies follow certain standards for the preparation and disclosure of reserves and related information. Nexen’s reserves disclosures are made in reliance upon exemptions granted to it by Canadian securities regulators from certain requirements of NI 51-101 which permits us to:
● prepare our reserves estimates and related disclosures in accordance with SEC disclosure requirements, generally accepted industry practices in the US and the Canadian Oil and Gas Evaluation Handbook (COGE Handbook) standards modified to reflect SEC requirements;
● substitute those SEC disclosures for much of the annual disclosure required by NI 51-101; and
● rely upon internally-generated reserves estimates and the Standardized Measure of Discounted Future Net Cash Flows and Changes Therein, included in the Supplementary Financial Information, without the requirement to have those estimates evaluated or audited by independent qualified reserves consultants.
As a result of these exemptions, Nexen’s disclosures may differ from other Canadian companies and Canadian investors should note the following fundamental differences in reserves estimates and related disclosures contained in the Form 10-K:
● SEC registrants apply SEC reserves definitions and prepare their reserves estimates in accordance with SEC requirements and generally accepted industry practices in the US whereas NI 51-101 requires adherence to the definitions and standards promulgated by the COGE Handbook;
● the SEC’s technical rules in estimating reserves differ from NI 51-101 in areas such as the use of reliable technology, aerial extent around a drilled location, quantities below the lowest known oil and quantities across an undrilled fault block;
● the SEC mandates disclosure of proved reserves and the Standardized Measure of Discounted Future Net Cash Flows and Changes Therein calculated using the year’s 12-month average prices and costs only whereas NI 51-101 requires disclosure of reserves and related future net revenues using forecast prices;
● the SEC mandates disclosure of reserves by geographic area only whereas NI 51-101 requires disclosure of more reserve categories and product types;
● the SEC prescribes certain information about proved and probable undeveloped reserves and future developments costs whereas NI 51-101 requirements are different;
● the SEC does not require disclosure of finding and development (F&D) costs per boe of proved reserves additions whereas NI 51-101 requires that various F&D costs per boe and additional information be disclosed;
● the SEC leaves the engagement of independent qualified reserves consultants to the discretion of a company’s board of directors whereas NI 51-101 requires issuers to engage such evaluators;
● the SEC does not allow proved and probable reserves to be aggregated whereas NI 51-101 requires issuers disclose such; and
● the reserves disclosures in this document have not been reviewed by the independent qualified reserves consultants whereas NI 51-101 requires them to review it.
The foregoing is a general description of the principal differences only. The differences between SEC requirements and NI 51-101 may be material.
NI 51-101 requires that we make the following disclosures:
● we use oil equivalents (boe) to express quantities of natural gas and crude oil in a common unit. A conversion ratio of 6 mcf of natural gas to 1 barrel of oil is used. Boe may be misleading, particularly if used in isolation. The conversion ratio
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is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead; and
● because reserves data are based on judgments regarding future events actual results will vary and the variations may be material. Variations as a result of future events are expected to be consistent with the fact that reserves are categorized according to the probability of their recovery.
Resources
Nexen’s estimates of contingent resources are based on definitions set out in the Canadian Oil and Gas Evaluation Handbook which generally describe contingent resources as those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. Such contingencies may include, but are not limited to, factors such as economic, legal, environmental, political and regulatory matters or a lack of markets. Specific contingencies precluding these contingent resources being classified as reserves include but are not limited to: future drilling program results, drilling and completions optimization, stakehol der and regulatory approval of future drilling and infrastructure plans, access to required infrastructure, economic fiscal terms, a lower level of delineation, the absence of regulatory approvals, detailed design estimates and near-term development plans, and general uncertainties associated with this early stage of evaluation. The estimated range of contingent resources reflects conservative and optimistic likelihoods of recovery. However, there is no certainty that it will be commercially viable to produce any portion of these contingent resources.
Nexen’s estimates of discovered resources (equivalent to discovered petroleum initially-in-place) are based on definitions set out in the Canadian Oil and Gas Evaluation Handbook which generally describe discovered resources as those quantities of petroleum estimated, as of a given date, to be contained in known accumulations prior to production. Discovered resources do not represent recoverable volumes. We disclose additional information regarding resource estimates in accordance with NI 51-101. These disclosures can be found on our website and on SEDAR.
Cautionary statement: In the case of discovered resources or a subcategory of discovered resources other than reserves, there is no certainty that it will be commercially viable to produce any portion of the resources. In the case of undiscovered resources or a subcategory of undiscovered resources, there is no certainty that any portion of the resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the resources.
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Nexen Inc.
Financial Highlights
Three Months Ended March 31 | ||||
| (Cdn$ millions) | 2010 | 2009 | ||
| Net Sales | 1,501 | 1,048 | ||
| Cash Flow from Operations | 538 | 557 | ||
Per Common Share ($/share) | 1.03 | 1.07 | ||
| Net Income | 185 | 135 | ||
Per Common Share ($/share) | 0.35 | 0.26 | ||
Capital Investment 1 | 556 | 1,504 | ||
Net Debt 2 | 5,057 | 5,737 | ||
Common Shares Outstanding (millions of shares) | 524.0 | 520.8 | ||
| 1 | Includes oil and gas development, exploration, and expenditures for other property, plant and equipment. |
| 2 | Net debt is defined as long-term debt and short-term borrowings less cash and cash equivalents. |
Cash Flow from Operations1
Three Months Ended March 31 | ||||
| (Cdn$ millions) | 2010 | 2009 | ||
| Oil & Gas | ||||
United Kingdom | 671 | 430 | ||
Canada | 60 | 34 | ||
Long Lake | (58) | – | ||
Syncrude | 60 | 26 | ||
United States | 78 | 12 | ||
Yemen 2 | 99 | 87 | ||
Other Countries | 6 | 9 | ||
| Marketing | (59) | 84 | ||
| 857 | 682 | |||
| Chemicals | 22 | 27 | ||
| 879 | 709 | |||
| Interest and Other Corporate Items | (125) | (58) | ||
Income Taxes 3 | (216) | (94) | ||
Cash Flow from Operations 1 | 538 | 557 | ||
| 1 | Defined as cash flow from operating activities before changes in non-cash working capital and other. We evaluate our performance and that of our business segments based on earnings and cash flow from operations. Cash flow from operations is a non-GAAP term that represents cash generated from operating activities before changes in non-cash working capital and other and excludes items of a non-recurring nature. We consider it a key measure as it demonstrates our ability and the ability of our business segments to generate the cash flow necessary to fund future growth through capital investment and repay debt. Cash flow from operations may not be comparable with the calculation of similar measures for other companies. |
Three Months Ended March 31 | ||||||||
| (Cdn$ millions) | 2010 | 2009 | ||||||
| Cash Flow from Operating Activities | 798 | 789 | ||||||
| Changes in Non-Cash Working Capital | (256 | ) | (420 | ) | ||||
| Other | 6 | 141 | ||||||
| Impact of Annual Crude Oil Put Options | (10 | ) | 47 | |||||
| Cash Flow from Operations | 538 | 557 | ||||||
| Weighted-average Number of Common Shares Outstanding (millions of shares) | 523.6 | 520.2 | ||||||
| Cash Flow from Operations Per Common Share ($/share) | 1.03 | 1.07 | ||||||
2 | After in-country cash taxes of $43 million for the three months ended March 31, 2010 (2009 – $24 million). |
3 | Excludes in-country cash taxes in Yemen. |
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Nexen Inc.
Production Volumes (before royalties) 1
Three Months Ended March 31 | ||||
| 2010 | 2009 | |||
Crude Oil and Liquids (mbbls/d) | ||||
United Kingdom | 105.6 | 103.8 | ||
Canada | 14.2 | 15.5 | ||
Long Lake Bitumen | 12.1 | 8.1 | ||
Syncrude | 19.5 | 19.8 | ||
United States | 9.8 | 10.4 | ||
Yemen | 42.8 | 54.5 | ||
Other Countries | 2.3 | 5.5 | ||
| 206.3 | 217.6 | |||
Natural Gas (mmcf/d) | ||||
United Kingdom | 40 | 18 | ||
Canada | 133 | 137 | ||
United States | 101 | 50 | ||
| 274 | 205 | |||
Total Production (mboe/d) | 252 | 252 | ||
Production Volumes (after royalties)
Three Months Ended March 31 | ||||
| 2010 | 2009 | |||
Crude Oil and Liquids (mbbls/d) | ||||
United Kingdom | 105.6 | 103.8 | ||
Canada | 11.0 | 12.3 | ||
Long Lake Bitumen | 11.3 | 8.1 | ||
Syncrude | 17.8 | 19.6 | ||
United States | 8.9 | 9.5 | ||
Yemen | 23.1 | 35.7 | ||
Other Countries | 2.1 | 5.1 | ||
| 179.8 | 194.1 | |||
Natural Gas (mmcf/d) | ||||
United Kingdom | 40 | 18 | ||
Canada | 121 | 122 | ||
United States | 88 | 45 | ||
| 249 | 185 | |||
Total Production (mboe/d) | 221 | 225 | ||
| 1 | We have presented production volumes before royalties as we measure our performance on this basis consistent with other Canadian oil and gas companies. |
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Nexen Inc.
Oil and Gas Prices and Cash Netback 1
| Quarters – 2010 | Quarters 2009 | Total Year | ||||||||||||||||||||||
| (all dollar amounts in Cdn$ unless noted) | 1st | 1st | 2nd | 3rd | 4th | 2009 | ||||||||||||||||||
| PRICES: | ||||||||||||||||||||||||
WTI Crude Oil (US$/bbl) | 78.71 | 43.08 | 59.62 | 68.30 | 76.19 | 61.80 | ||||||||||||||||||
Nexen Average – Oil (Cdn$/bbl) | 78.00 | 50.41 | 68.32 | 72.95 | 76.39 | 66.85 | ||||||||||||||||||
NYMEX Natural Gas (US$/mmbtu) | 5.04 | 4.48 | 3.81 | 3.44 | 4.91 | 4.16 | ||||||||||||||||||
Nexen Average – Gas (Cdn$/mcf) | 5.37 | 5.11 | 3.77 | 3.04 | 4.31 | 4.06 | ||||||||||||||||||
| NETBACKS: | ||||||||||||||||||||||||
| United Kingdom | ||||||||||||||||||||||||
| Crude Oil: | ||||||||||||||||||||||||
Sales (mbbls/d) | 106.5 | 100.8 | 97.0 | 70.4 | 119.6 | 96.9 | ||||||||||||||||||
Price Received ($/bbl) | 77.25 | 51.60 | 69.42 | 73.15 | 76.40 | 67.70 | ||||||||||||||||||
| Natural Gas: | ||||||||||||||||||||||||
Sales (mmcf/d) | 33 | 21 | 17 | 17 | 43 | 24 | ||||||||||||||||||
Price Received ($/mcf) | 4.81 | 5.50 | 3.67 | 2.64 | 3.82 | 3.95 | ||||||||||||||||||
Total Sales Volume (mboe/d) | 112.1 | 104.3 | 99.8 | 73.2 | 126.8 | 101.0 | ||||||||||||||||||
Price Received ($/boe) | 74.84 | 50.97 | 68.10 | 70.95 | 73.39 | 65.93 | ||||||||||||||||||
| Operating Costs | 7.60 | 5.48 | 5.85 | 10.34 | 6.77 | 6.87 | ||||||||||||||||||
| Netback | 67.24 | 45.49 | 62.25 | 60.61 | 66.62 | 59.06 | ||||||||||||||||||
Canada – Heavy Oil & Bitumen 2 | ||||||||||||||||||||||||
Sales (mbbls/d) | 22.62 | 15.4 | 14.7 | 14.0 | 13.5 | 14.4 | ||||||||||||||||||
Price Received ($/bbl) | 71.24 | 35.35 | 56.05 | 59.88 | 62.53 | 53.04 | ||||||||||||||||||
| Royalties & Other | 10.27 | 6.86 | 12.83 | 13.47 | 14.07 | 11.70 | ||||||||||||||||||
Operating & Other Costs 3 | 67.57 | 15.42 | 16.41 | 16.21 | 16.73 | 16.17 | ||||||||||||||||||
| Netback | (6.60 | ) | 13.07 | 26.81 | 30.20 | 31.73 | 25.17 | |||||||||||||||||
| Canada – Natural Gas | ||||||||||||||||||||||||
Sales (mmcf/d) | 124 | 137 | 134 | 136 | 130 | 134 | ||||||||||||||||||
Price Received ($/mcf) | 5.02 | 4.75 | 3.42 | 2.85 | 4.14 | 3.78 | ||||||||||||||||||
| Royalties & Other | 0.40 | 0.59 | 0.15 | 0.21 | 0.34 | 0.32 | ||||||||||||||||||
| Operating Costs | 1.70 | 1.54 | 1.59 | 1.82 | 2.10 | 1.76 | ||||||||||||||||||
| Netback | 2.92 | 2.62 | 1.68 | 0.82 | 1.70 | 1.70 | ||||||||||||||||||
| Syncrude | ||||||||||||||||||||||||
Sales (mbbls/d) | 19.5 | 19.8 | 14.9 | 22.5 | 23.7 | 20.2 | ||||||||||||||||||
Price Received ($/bbl) | 83.55 | 55.48 | 71.58 | 74.54 | 79.83 | 70.96 | ||||||||||||||||||
| Royalties & Other | 7.09 | 0.40 | 8.84 | 8.31 | 6.75 | 6.04 | ||||||||||||||||||
| Operating Costs | 38.43 | 36.95 | 57.21 | 29.50 | 27.93 | 35.92 | ||||||||||||||||||
| Netback | 38.03 | 18.13 | 5.53 | 36.73 | 45.15 | 29.00 | ||||||||||||||||||
| 1 | Defined as average sales price less royalties and other, operating costs, and in-country taxes in Yemen. |
| 2 | 2010 includes results from our start up activities at Long Lake. |
3 | 2010 includes Long Lake third-party bitumen purchases. |
11
Nexen Inc.
Oil and Gas Cash Netback 1 (continued)
| Quarters – 2010 | Quarters – 2009 | Total Year | ||||||||||||||||||||||
| (all dollar amounts in Cdn$ unless noted) | 1st | 1st | 2nd | 3rd | 4th | 2009 | ||||||||||||||||||
| United States | ||||||||||||||||||||||||
| Crude Oil: | ||||||||||||||||||||||||
Sales (mbbls/d) | 9.8 | 10.4 | 12.1 | 9.5 | 10.0 | 10.5 | ||||||||||||||||||
Price Received ($/bbl) | 79.12 | 46.27 | 66.23 | 72.27 | 75.75 | 65.01 | ||||||||||||||||||
| Natural Gas: | ||||||||||||||||||||||||
Sales (mmcf/d) | 101 | 50 | 61 | 63 | 84 | 65 | ||||||||||||||||||
Price Received ($/mcf) | 6.00 | 5.93 | 4.58 | 3.56 | 4.83 | 4.67 | ||||||||||||||||||
Total Sales Volume (mboe/d) | 26.60 | 18.8 | 22.2 | 20.0 | 23.9 | 21.2 | ||||||||||||||||||
Price Received ($/boe) | 51.92 | 41.50 | 48.53 | 45.43 | 48.55 | 46.27 | ||||||||||||||||||
| Royalties & Other | 4.92 | 4.52 | 4.94 | 4.77 | 5.21 | 4.89 | ||||||||||||||||||
| Operating Costs | 8.96 | 13.79 | 13.11 | 12.40 | 11.32 | 12.58 | ||||||||||||||||||
| Netback | 38.04 | 23.19 | 30.48 | 28.26 | 32.02 | 28.80 | ||||||||||||||||||
| Yemen | ||||||||||||||||||||||||
Sales (mbbls/d) | 47.3 | 54.7 | 51.4 | 43.2 | 46.2 | 48.8 | ||||||||||||||||||
Price Received ($/bbl) | 80.39 | 52.30 | 69.40 | 76.31 | 78.93 | 68.49 | ||||||||||||||||||
| Royalties & Other | 37.52 | 19.43 | 31.94 | 32.08 | 33.71 | 28.94 | ||||||||||||||||||
| Operating Costs | 9.67 | 9.62 | 10.39 | 12.43 | 10.62 | 10.69 | ||||||||||||||||||
| In-country Taxes | 10.14 | 4.92 | 9.01 | 9.70 | 10.17 | 8.31 | ||||||||||||||||||
| Netback | 23.06 | 18.33 | 18.06 | 22.10 | 24.43 | 20.55 | ||||||||||||||||||
| Other Countries | ||||||||||||||||||||||||
Sales (mbbls/d) | 2.3 | 5.5 | 3.6 | 2.6 | 2.4 | 3.5 | ||||||||||||||||||
Price Received ($/bbl) | 78.88 | 41.68 | 66.83 | 70.49 | 74.10 | 59.05 | ||||||||||||||||||
| Royalties & Other | 5.72 | 3.26 | 5.17 | 5.38 | 5.48 | 4.52 | ||||||||||||||||||
| Operating Costs | 5.58 | 4.81 | 5.73 | 5.70 | 9.52 | 6.03 | ||||||||||||||||||
| Netback | 67.58 | 33.61 | 55.93 | 59.41 | 59.10 | 48.50 | ||||||||||||||||||
| Company-Wide | ||||||||||||||||||||||||
Oil and Gas Sales (mboe/d) | 251.1 | 241.4 | 228.9 | 198.2 | 258.1 | 231.6 | ||||||||||||||||||
Price Received ($/boe) | 70.16 | 47.56 | 61.28 | 63.00 | 68.04 | 60.02 | ||||||||||||||||||
| Royalties & Other | 9.32 | 5.64 | 9.23 | 9.58 | 8.09 | 8.06 | ||||||||||||||||||
Operating and Other Costs 2 | 16.14 | 10.62 | 11.95 | 13.60 | 10.86 | 11.66 | ||||||||||||||||||
| In-country Taxes | 1.91 | 1.11 | 2.02 | 2.11 | 1.82 | 1.75 | ||||||||||||||||||
| Netback | 42.79 | 30.19 | 38.08 | 37.71 | 47.27 | 38.55 | ||||||||||||||||||
| 1 | Defined as average sales price less royalties and other, operating costs, and in-country taxes in Yemen. | |
| 2 | 2010 includes Long Lake third-party bitumen purchases. | |
12
Nexen Inc.
Unaudited Consolidated Statement of Income
For the Three Months Ended March 31
| (Cdn$ millions, except per share amounts) | 2010 | 2009 | ||||||
| Revenues and Other Income | ||||||||
Net Sales | 1,501 | 1,048 | ||||||
Marketing and Other (Note 14) | 151 | 257 | ||||||
| 1,652 | 1,305 | |||||||
| Expenses | ||||||||
Operating | 422 | 305 | ||||||
Depreciation, Depletion, Amortization and Impairment | 388 | 409 | ||||||
Transportation and Other | 202 | 201 | ||||||
General and Administrative | 118 | 100 | ||||||
Exploration | 93 | 53 | ||||||
Interest (Note 9) | 80 | 68 | ||||||
| 1,303 | 1,136 | |||||||
| Income before Provision for Income Taxes | 349 | 169 | ||||||
| Provision for (Recovery of) Income Taxes | ||||||||
Current | 259 | 118 | ||||||
Future | (100 | ) | (87 | ) | ||||
| 159 | 31 | |||||||
| Net Income | 190 | 138 | ||||||
Less: Net Income Attributable to Canexus Non-Controlling Interests | 5 | 3 | ||||||
| Net Income Attributable to Nexen Inc. | 185 | 135 | ||||||
Earnings Per Common Share ($/share) (Note 15) | ||||||||
Basic | 0.35 | 0.26 | ||||||
Diluted | 0.35 | 0.26 | ||||||
See accompanying notes to the Unaudited Consolidated Financial Statements.
13
Nexen Inc.
Unaudited Consolidated Balance Sheet
| March 31 | December 31 | |||||||
| (Cdn$ millions, except share amounts) | 2010 | 2009 | ||||||
| Assets | ||||||||
Current Assets | ||||||||
Cash and Cash Equivalents | 1,997 | 1,700 | ||||||
Restricted Cash | 178 | 198 | ||||||
Accounts Receivable (Note 2) | 2,635 | 2,788 | ||||||
Inventories and Supplies (Note 3) | 574 | 680 | ||||||
Other | 102 | 185 | ||||||
Total Current Assets | 5,486 | 5,551 | ||||||
Property, Plant and Equipment | ||||||||
Net of Accumulated Depreciation, Depletion, Amortization and Impairment of $10,931 (December 31, 2009 – $10,807) | 15,381 | 15,492 | ||||||
Goodwill | 330 | 339 | ||||||
Future Income Tax Assets | 1,238 | 1,148 | ||||||
Deferred Charges and Other Assets (Note 5) | 328 | 370 | ||||||
| Total Assets | 22,763 | 22,900 | ||||||
| Liabilities | ||||||||
Current Liabilities | ||||||||
Accounts Payable and Accrued Liabilities (Note 8) | 3,084 | 3,038 | ||||||
Accrued Interest Payable | 77 | 89 | ||||||
Dividends Payable | 26 | 26 | ||||||
Total Current Liabilities | 3,187 | 3,153 | ||||||
Long-Term Debt (Note 9) | 7,054 | 7,251 | ||||||
Future Income Tax Liabilities | 2,804 | 2,811 | ||||||
Asset Retirement Obligations (Note 11) | 932 | 1,018 | ||||||
Deferred Credits and Other Liabilities (Note 12) | 959 | 1,021 | ||||||
| Equity | ||||||||
Nexen Inc. Shareholders’ Equity | ||||||||
Common Shares, no par value | ||||||||
Authorized:Unlimited | ||||||||
Outstanding:2010 – 524,046,867 shares | ||||||||
2009 – 522,915,843 shares | 1,076 | 1,049 | ||||||
Contributed Surplus | – | 1 | ||||||
Retained Earnings | 6,881 | 6,722 | ||||||
Accumulated Other Comprehensive Loss | (201 | ) | (190 | ) | ||||
Total Nexen Inc. Shareholders’ Equity | 7,756 | 7,582 | ||||||
Canexus Non-Controlling Interests | 71 | 64 | ||||||
Total Equity | 7,827 | 7,646 | ||||||
Commitments, Contingencies and Guarantees (Note 16) | ||||||||
| Total Liabilities and Equity | 22,763 | 22,900 | ||||||
See accompanying notes to the Unaudited Consolidated Financial Statements.
14
Nexen Inc.
Unaudited Consolidated Statement of Cash Flows
For the Three Months Ended March 31
| (Cdn$ millions) | 2010 | 2009 | ||||||
| Operating Activities | ||||||||
Net Income | 190 | 138 | ||||||
Charges and Credits to Income not Involving Cash (Note 17) | 265 | 319 | ||||||
Exploration Expense | 93 | 53 | ||||||
Changes in Non-Cash Working Capital (Note 17) | 256 | 420 | ||||||
Other | (6 | ) | (141 | ) | ||||
| 798 | 789 | |||||||
| Financing Activities | ||||||||
Proceeds from (Repayment of) Term Credit Facilities, Net | – | 1,011 | ||||||
Proceeds from (Repayment of) Canexus Term Credit Facilities, Net | 22 | 10 | ||||||
Dividends Paid on Common Shares | (26 | ) | (26 | ) | ||||
Distributions Paid to Canexus Non-Controlling Interests | (4 | ) | (4 | ) | ||||
Issue of Common Shares and Exercise of Tandem Options for Shares | 25 | 23 | ||||||
| 17 | 1,014 | |||||||
| Investing Activities | ||||||||
Capital Expenditures | ||||||||
Exploration and Development | (492 | ) | (702 | ) | ||||
Proved Property Acquisitions | – | (757 | ) | |||||
Energy Marketing, Chemicals, Corporate and Other | (64 | ) | (45 | ) | ||||
Proceeds on Disposition of Assets | 15 | 14 | ||||||
Changes in Non-Cash Working Capital (Note 17) | 88 | 19 | ||||||
Changes in Restricted Cash | 15 | (314 | ) | |||||
Other | (3 | ) | (2 | ) | ||||
| (441 | ) | (1,787 | ) | |||||
| Effect of Exchange Rate Changes on Cash and Cash Equivalents | (77 | ) | 35 | |||||
| Increase in Cash and Cash Equivalents | 297 | 51 | ||||||
| Cash and Cash Equivalents – Beginning of Period | 1,700 | 2,003 | ||||||
Cash and Cash Equivalents – End of Period 1 | 1,997 | 2,054 | ||||||
1 | Cash and cash equivalents at March 31, 2010 consist of cash of $257 million and short-term investments of $1,740 million (March 31, 2009 – cash of $182 million and short-term investments of $1,872 million). |
See accompanying notes to the Unaudited Consolidated Financial Statements.
15
Nexen Inc.
Unaudited Consolidated Statement of Equity
For the Three Months Ended March 31
| (Cdn$ millions) | 2010 | 2009 | ||||||
Common Shares, Beginning of Period | 1,049 | 981 | ||||||
Issue of Common Shares | 24 | 23 | ||||||
Exercise of Tandem Options for Shares | 1 | – | ||||||
Accrued Liability Relating to Tandem Options Exercised for Common Shares | 2 | – | ||||||
Balance at End of Period | 1,076 | 1,004 | ||||||
Contributed Surplus, Beginning of Period | 1 | 2 | ||||||
Exercise of Tandem Options | (1 | ) | – | |||||
Balance at End of Period | – | 2 | ||||||
Retained Earnings, Beginning of Period | 6,722 | 6,290 | ||||||
Net Income Attributable to Nexen Inc. | 185 | 135 | ||||||
Dividends Paid on Common Shares (Note 13) | (26 | ) | (26 | ) | ||||
Balance at End of Period | 6,881 | 6,399 | ||||||
Accumulated Other Comprehensive Loss, Beginning of Period | (190 | ) | (134 | ) | ||||
Other Comprehensive Income (Loss) Attributable to Nexen Inc. | (11 | ) | 6 | |||||
Balance at End of Period 1 | (201 | ) | (128 | ) | ||||
1 Comprised of unrealized foreign currency translation adjustment. | ||||||||
Canexus Non-Controlling Interests, Beginning of Period | 64 | 52 | ||||||
Net Income Attributable to Non-Controlling Interests | 6 | 3 | ||||||
Distributions Paid to Non-Controlling Interests | (4 | ) | (4 | ) | ||||
Issue of Partnership Units to Non-Controlling Interests | 5 | 1 | ||||||
Balance at End of Period | 71 | 52 | ||||||
See accompanying notes to the Unaudited Consolidated Financial Statements.
Nexen Inc.
Unaudited Consolidated Statement of Comprehensive Income
For the Three Months Ended March 31
| (Cdn$ millions) | 2010 | 2009 | ||||||
| Net Income Attributable to Nexen Inc. | 185 | 135 | ||||||
Other Comprehensive Income (Loss), Net of Income Taxes: | ||||||||
Foreign Currency Translation Adjustment | ||||||||
Net Gains (Losses) on Investment in Self-Sustaining Foreign Operations | (147 | ) | 174 | |||||
Net Gains (Losses) on Foreign-Denominated Debt Hedges of Self-Sustaining Foreign Operations 1 | 136 | (168 | ) | |||||
Other Comprehensive Income (Loss) Attributable to Nexen Inc. | (11 | ) | 6 | |||||
| Comprehensive Income Attributable to Nexen Inc. | 174 | 141 | ||||||
| 1 | Net of income tax expense for the three months ended March 31, 2010 of $20 million (2009 – $24 million recovery). |
| See accompanying notes to the Unaudited Consolidated Financial Statements. |
16
| Nexen Inc. |
| Notes to Unaudited Consolidated Financial Statements |
| Cdn$ millions, except as noted |
| 1. | ACCOUNTING POLICIES |
Our Unaudited Consolidated Financial Statements are prepared in accordance with Canadian Generally Accepted Accounting Principles (GAAP). The impact of significant differences between Canadian and United States GAAP on the Unaudited Consolidated Financial Statements is disclosed in Note 20. In the opinion of management, the Unaudited Consolidated Financial Statements contain all adjustments of a normal and recurring nature necessary to present fairly Nexen Inc.’s (Nexen, we or our) financial position at March 31, 2010 and December 31, 2009 and the results of our operations and our cash flows for the three months ended March 31, 2010 and 2009.
We make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the Unaudited Consolidated Financial Statements, and revenues and expenses during the reporting period. Our management reviews these estimates on an ongoing basis, including those related to accruals, litigation, environmental and asset retirement obligations, recoverability of assets, income taxes, fair values of derivative assets and liabilities, capital adequacy and determination of proved reserves. Changes in facts and circumstances may result in revised estimates and actual results may differ from these estimates. The results of operations and cash flows for the three months ended March 31, 2010 are not necessarily indicative of the results of operations or cash fl ows to be expected for the year ending December 31, 2010. As at April 26, 2010, there are no material subsequent events requiring additional disclosure in or amendment to these financial statements.
These Unaudited Consolidated Financial Statements should be read in conjunction with our Audited Consolidated Financial Statements included in our 2009 Form 10-K. The accounting policies we follow are described in Note 1 of the Audited Consolidated Financial Statements included in our 2009 Form 10-K.
Changes in Accounting Policies
Oil and Gas Reserve Estimates
On January 6, 2010, the Financial Accounting Standards Board issued guidance for Oil and Gas Reserve Estimation and Disclosure, which is effective for years ended December 31, 2009. The guidance expands the definition of oil and gas producing activities to: i) include unconventional sources such as oil sands; ii) change the price used in reserve estimation from the year-end price to the simple average of the first-day-of-the-month price for the previous 12 months, and iii) require disclosures for geographic areas that represent 15% or more of proved reserves.
We follow the successful efforts method of accounting for our oil and gas activities, which use the estimated proved reserves we believe are recoverable from our oil and gas properties. Specifically, reserves estimates are used to calculate our unit-of-production depletion rates and to assess, when necessary, our oil and gas assets for impairment. Adoption of these amendments changed our estimate of reserves used to calculate depletion in 2010. As a result of the amendments, depletion expense for the three months ended March 31, 2010 increased by $14 million, net income decreased by $9 million, and earnings per common share decreased by $0.02/share.
| 2. | ACCOUNTS RECEIVABLE |
March 31 2010 | December 31 2009 | |||||||
| Trade | ||||||||
| Energy Marketing | 1,385 | 1,410 | ||||||
| Energy Marketing Derivative Contracts (Note 6) | 267 | 466 | ||||||
| Oil and Gas | 867 | 823 | ||||||
| Chemicals and Other | 46 | 44 | ||||||
| 2,565 | 2,743 | |||||||
| Non-Trade | 123 | 99 | ||||||
| 2,688 | 2,842 | |||||||
| Allowance for Doubtful Receivables | (53 | ) | (54 | ) | ||||
| Total | 2,635 | 2,788 | ||||||
17
| 3. | INVENTORIES AND SUPPLIES |
March 31 2010 | December 31 2009 | |||||||
| Finished Products | ||||||||
Energy Marketing | 442 | 548 | ||||||
Oil and Gas | 25 | 25 | ||||||
Chemicals and Other | 12 | 12 | ||||||
| 479 | 585 | |||||||
| Work in Process | 10 | 7 | ||||||
| Field Supplies | 85 | 88 | ||||||
| Total | 574 | 680 | ||||||
| 4. | SUSPENDED EXPLORATION WELL COSTS |
The following table shows the changes in capitalized exploratory well costs during the three months ended March 31, 2010 and the year ended December 31, 2009, and does not include amounts that were initially capitalized and subsequently expensed in the same period. Suspended exploration well costs are included in property, plant and equipment.
| Three Months Ended March 31 2010 | Year Ended December 31 2009 | |||||||
| Beginning of Period | 794 | 518 | ||||||
Exploratory Well Costs Capitalized Pending the Determination of Proved Reserves | 146 | 396 | ||||||
Capitalized Exploratory Well Costs Charged to Expense | (2 | ) | (56 | ) | ||||
Transfers to Wells, Facilities and Equipment Based on Determination of Proved Reserves | – | (21 | ) | |||||
Effects of Foreign Exchange Rate Changes | (14 | ) | (43 | ) | ||||
| End of Period | 924 | 794 | ||||||
The following table provides an aging of capitalized exploratory well costs based on the date drilling was completed and shows the number of projects for which exploratory well costs have been capitalized for a period greater than one year after the completion of drilling.
March 31 2010 | December 31 2009 | |||||||
| Capitalized for a Period of One Year or Less | 425 | 383 | ||||||
| Capitalized for a Period of Greater than One Year | 499 | 411 | ||||||
| Total | 924 | 794 | ||||||
Number of Projects that have Exploratory Well Costs Capitalized for a Period Greater than One Year | 13 | 12 | ||||||
18
As at March 31, 2010, we have exploratory costs that have been capitalized for more than one year relating to our interests in eight exploratory blocks in the North Sea ($174 million), certain coalbed methane and shale gas exploratory activities in Canada ($194 million), two exploratory blocks in the Gulf of Mexico ($113 million), and our interest in an exploratory block offshore Nigeria ($18 million). These costs relate to projects with successful exploration wells for which we have not been able to recognize proved reserves. We are assessing all of these wells and projects, and are working with our partners to prepare development plans, drill additional appraisal wells or otherwise assess commercial viability.
Aging of Suspended Exploration Wells Greater than One Year | United Kingdom | Canada | United States | Nigeria | Total |
| 1-3 years | 119 | 194 | 42 | – | 355 |
| 4-5 years | 55 | – | 71 | – | 126 |
| Greater than 5 years | – | – | – | 18 | 18 |
| Total | 174 | 194 | 113 | 18 | 499 |
| 5. | DEFERRED CHARGES AND OTHER ASSETS |
March 31 2010 | December 31 2009 | |||||||
Long-Term Energy Marketing Derivative Contracts (Note 6) | 200 | 225 | ||||||
Crude Oil Put Options and Natural Gas Swaps (Note 6) | – | 4 | ||||||
| Defined Benefit Pension Assets | 56 | 60 | ||||||
| Long-Term Capital Prepayments | 23 | 27 | ||||||
| Other | 49 | 54 | ||||||
| Total | 328 | 370 | ||||||
| 6. | FINANCIAL INSTRUMENTS |
Financial instruments carried at fair value on our balance sheet include cash and cash equivalents, restricted cash and derivatives used for trading and non-trading purposes. Our other financial instruments, including accounts receivable, accounts payable, accrued interest payable, dividends payable, short-term borrowings and long-term debt, are carried at cost or amortized cost. The carrying values of our short-term receivables and payables approximate their fair value because the instruments are near maturity.
In our energy marketing group, we enter into contracts to purchase and sell crude oil, natural gas and other energy commodities, and use derivative contracts, including futures, forwards, swaps and options, for hedging and trading purposes (collectively derivatives). We also use derivatives to manage commodity price risk and foreign currency risk for non-trading purposes. We categorize our derivative instruments as trading or non-trading activities and carry the instruments at fair value on our balance sheet. The derivatives section below details our derivatives and fair values as at March 31, 2010. The fair values are included with accounts receivable or payable and are classified as long-term or short-term based on anticipated settlement date. Any change in fair value is included in marketing and other income. Related amount s posted as margin for exchange traded positions are recorded in restricted cash.
We carry our long-term debt at amortized cost using the effective interest rate method. At March 31, 2010, the estimated fair value of our long-term debt was $7,337 million (December 31, 2009 – $7,594 million) as compared to the carrying value of $7,054 million (December 31, 2009 – $7,251 million). The fair value of long-term debt is estimated based on prices provided by quoted markets and third-party brokers.
19
Derivatives
| (a) | Derivative contracts related to trading activities |
Our energy marketing group engages in various activities including the purchase and sale of physical commodities and the use of financial instruments such as commodity and foreign exchange futures, forwards and swaps to economically hedge exposures and generate revenue. These contracts are accounted for as derivatives and, where applicable, are presented net on the balance sheet in accordance with netting arrangements. The fair value and carrying amounts related to derivative instruments held by our energy marketing operations are as follows:
March 31 2010 | December 31 2009 | |||||||
Commodity Contracts | 267 | 463 | ||||||
Foreign Exchange Contracts | – | 3 | ||||||
Accounts Receivable (Note 2) | 267 | 466 | ||||||
Commodity Contracts | 200 | 225 | ||||||
Deferred Charges and Other Assets (Note 5) 1 | 200 | 225 | ||||||
| Total Trading Derivative Assets | 467 | 691 | ||||||
Commodity Contracts | 212 | 410 | ||||||
Foreign Exchange Contracts | 13 | 46 | ||||||
Accounts Payable and Accrued Liabilities (Note 8) | 225 | 456 | ||||||
Commodity Contracts | 198 | 212 | ||||||
Foreign Exchange Contracts | 1 | – | ||||||
Deferred Credits and Other Liabilities (Note 12) 1 | 199 | 212 | ||||||
| Total Trading Derivative Liabilities | 424 | 668 | ||||||
| Total Net Trading Derivative Contracts | 43 | 23 | ||||||
| 1 | These derivative contracts settle beyond 12 months and are considered non-current; once settlement is within 12 months, they are included in accounts receivable or accounts payable. |
Excluding the impact of netting arrangements, the fair value of derivative instruments is as follows:
March 31 2010 | December 31 2009 | |||||||
| Current Trading Assets | 2,116 | 2,625 | ||||||
| Non-Current Trading Assets | 613 | 716 | ||||||
Total Trading Derivative Assets | 2,729 | 3,341 | ||||||
| Current Trading Liabilities | 2,074 | 2,615 | ||||||
| Non-Current Trading Liabilities | 612 | 703 | ||||||
Total Trading Derivative Liabilities | 2,686 | 3,318 | ||||||
Total Net Trading Derivative Contracts | 43 | 23 | ||||||
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Trading revenues generated by our energy marketing group include gains and losses on derivative instruments and non-derivative instruments such as physical inventory. During the three months ended March 31, 2010 and 2009, the following trading revenues were recognized in marketing and other income:
| Three Months Ended March 31 | ||||||||
| 2010 | 2009 | |||||||
| Commodity | 91 | 270 | ||||||
| Foreign Exchange | (5 | ) | (3 | ) | ||||
Marketing Revenue | 86 | 267 | ||||||
As an energy marketer, we may undertake several transactions during a period to execute a single sale of physical product. Each transaction may be represented by one or more derivative instruments including a physical buy, physical sell, and in many cases, numerous financial instruments for economic hedging and trading purposes. The absolute notional volumes associated with our derivative instrument transactions for the three months ended March 31, 2010 and 2009, are as follows:
| Three Months Ended March 31 | |||||||||
| 2010 | 2009 | ||||||||
| Natural Gas | bcf/d | 15.2 | 28.6 | ||||||
| Crude Oil | mmbbls/d | 3.3 | 3.8 | ||||||
| Power | GWh/d | 280.8 | 212.3 | ||||||
| Foreign Exchange | US$ millions | 787 | 378 | ||||||
| Foreign Exchange | Euro millions | 53 | 153 | ||||||
| (b) | Derivative contracts related to non-trading activities |
The fair value and carrying amounts of derivative instruments related to non-trading activities are as follows:
March 31 2010 | December 31 2009 | |||||||
| Accounts Receivable | 1 | 13 | ||||||
Deferred Charges and Other Assets (Note 5) 1 | – | 4 | ||||||
Total Non-Trading Derivative Assets | 1 | 17 | ||||||
Accounts Payable and Accrued Liabilities (Note 8) | 20 | 26 | ||||||
Total Non-Trading Derivative Liabilities | 20 | 26 | ||||||
Total Net Non-Trading Derivative Assets 2 | (19 | ) | (9 | ) | ||||
| 1 | These derivative contracts settle beyond 12 months and are considered non-current. |
| 2 | The net fair value of these derivatives is equal to the gross fair value before consideration of netting arrangements and collateral posted or received with counterparties. |
Crude oil put options
In 2009, we purchased put options on 90,000 bbls/d of our 2010 crude oil production for $39 million. These options establish a WTI floor price of US$50/bbl on these volumes and provide a base level of price protection without limiting our upside to higher prices. Options on 60,000 bbls/d settle monthly, while the remaining options settle annually. These options are recorded at fair value throughout their term. As a result, changes in forward crude oil prices create gains or losses on these options at each period end. At March 31, 2010, higher crude oil prices reduced the fair value of the options to approximately $1 million, and we recorded a fair value loss during the period of $16 million in marketing and other income.
Three Months Ended March 31, 2010 | ||||||||||||||||||||
Notional Volumes | Term | Average Floor Price | Fair Value | Change in Fair Value | ||||||||||||||||
| (bbls/d) | (US$/bbl) | |||||||||||||||||||
| WTI Crude Oil Put Options (monthly) | 60,000 | 2010 | 50 | 1 | (12 | ) | ||||||||||||||
| WTI Crude Oil Put Options (annual) | 30,000 | 2010 | 50 | – | (4 | ) | ||||||||||||||
| 1 | (16 | ) | ||||||||||||||||||
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Fixed-price natural gas contracts and natural gas swaps
We have fixed-price natural gas sales contracts and offsetting natural gas swaps that are not part of our trading activities. These sales contracts and swaps are carried at fair value and are classified as current based on their anticipated settlement date. Any change in fair value is included in marketing and other income.
Three Months Ended March 31, 2010 | ||||||||||||||||||||
Notional Volumes | Term | Average Price | Fair Value | Change in Fair Value | ||||||||||||||||
| (Gj/d) | ($/Gj) | |||||||||||||||||||
| Fixed-Price Natural Gas Contracts | 15,514 | 2010 | 2.28 | (4 | ) | (7 | ) | |||||||||||||
| Natural Gas Swaps | 15,514 | 2010 | 7.60 | (16 | ) | 7 | ||||||||||||||
| (20 | ) | – | ||||||||||||||||||
| (c) | Fair value of derivatives |
Our processes for estimating and classifying the fair value of our derivative contracts are consistent with those in place at December 31, 2009. The following table includes our derivatives carried at fair value for our trading and non-trading activities as at March 31, 2010. Financial assets and liabilities are classified in the fair value hierarchy in their entirety based on the lowest level of input that is significant to the fair value measurement. Assessment of the significance of a particular input to the fair value measurement requires judgment and may affect placement within the fair value hierarchy levels.
| Net Derivatives at March 31, 2010 | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
Commodity Contracts | (156 | ) | 175 | 38 | 57 | |||||||||||
Foreign Exchange Contracts | – | (14 | ) | – | (14 | ) | ||||||||||
| Trading Derivatives | (156 | ) | 161 | 38 | 43 | |||||||||||
| Non-Trading Derivatives | – | (19 | ) | – | (19 | ) | ||||||||||
| Total | (156 | ) | 142 | 38 | 24 | |||||||||||
A reconciliation of changes in the fair value of our derivatives classified as Level 3 for the three months ended March 31, 2010 is provided below:
| Level 3 | ||||
| Beginning of Period | 42 | |||
Realized and Unrealized Gains (Losses) | 7 | |||
Purchases | – | |||
Settlements | (11 | ) | ||
Transfers Into Level 3 | – | |||
Transfers Out of Level 3 | – | |||
| End of Period | 38 | |||
| Unsettled gains relating to instruments still held as of March 31, 2010 | 7 | |||
Items classified in Level 3 are generally economically hedged such that gains or losses on positions classified in Level 3 are often offset by gains or losses on positions classified in Level 1 or 2. Transfers into or out of Level 3 represent existing assets and liabilities that were either previously categorized as a higher level for which the inputs became unobservable or assets and liabilities that were previously classified as Level 3 for which the lowest significant input became observable during the period. Fair values of instruments in Level 3 are determined using broker quotes, pricing services and internally-developed inputs. We performed a sensitivity analysis of inputs used to calculate the fair value of Level 3 instruments. Using reasonably possible alternative assumptions, the fair value of Level 3 instruments wou ld change by $13 million (December 31, 2009 – $12 million).
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| 7. | RISK MANAGEMENT |
| (a) | Market risk |
We invest in significant capital projects, purchase and sell commodities, issue short-term borrowings and long-term debt, and invest in foreign operations. These activities expose us to market risks from changes in commodity prices, foreign currency rates and interest rates, which could affect our earnings and the value of the financial instruments we hold. We use derivatives for trading and non-trading purposes as part of our overall risk management policy to manage these market exposures.
The following market risk discussion focuses on the commodity price risk and foreign currency risk related to our financial instruments as our exposure to interest rate risk is immaterial, given that the majority of our debt is fixed rate.
Commodity price risk
We are exposed to commodity price movements as part of our normal oil and gas operations, particularly in relation to the prices received for our crude oil and natural gas. Commodity price risk related to conventional and synthetic crude oil prices is our most significant market risk exposure. Crude oil and natural gas are sensitive to numerous worldwide factors, many of which are beyond our control, and are generally sold at contract or posted prices. Changes in the global supply and demand fundamentals in the crude oil market and geopolitical events can significantly affect crude oil prices. Changes in crude oil and natural gas prices may significantly affect our results of operations and cash generated from operating activities. Consequently, these changes may also affect the value of our oil and gas properties, our level o f spending for exploration and development, and our ability to meet our obligations as they come due.
The majority of our oil and gas production is sold under short-term contracts, exposing us to the risk of price movements. Other energy contracts we enter into also expose us to commodity price risk between the time we purchase and sell contracted volumes. We actively manage these risks by using derivative contracts such as commodity put options.
Our energy marketing business is focused on providing services to our customers and suppliers to meet their energy commodity needs. We market and trade physical energy commodities in selected regions of the world, including crude oil, natural gas, electricity and other commodities. We do this by buying and selling physical commodities, by acquiring and holding rights to physical transportation and storage assets for these commodities, and by building strong relationships with our customers and suppliers.
In order to manage the commodity and foreign exchange price risks that come from this physical business, we use financial derivative contracts including energy-related futures, forwards, swaps and options, as well as foreign currency swaps or forwards.
We also seek to profit from our views on the future movement of energy commodity pricing relationships, primarily between different locations, time periods or product qualities. We do this by holding open positions, where the terms of physical or financial contracts are not completely matched to offsetting positions.
Our risk management activities include prescribed capital limits and the use of tools such as Value-at-Risk (VaR) and stress testing consistent with the methodology used at December 31, 2009. Our period end, high, low and average VaR amounts for the three months ended March 31, 2010 and the year ended December 31, 2009, are as follows:
Value-at-Risk | Three Months Ended March 31 2010 | Year Ended December 31 2009 | ||||||
| Period End | 13 | 11 | ||||||
| High | 15 | 24 | ||||||
| Low | 9 | 9 | ||||||
| Average | 12 | 15 | ||||||
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If a market shock occurred as in 2008, the key assumptions underlying our VaR estimate could be exceeded and the potential loss could be greater than our estimate. We perform stress tests on a regular basis to complement VaR and assess the impact of abnormal changes in prices on our positions.
Foreign currency risk
Foreign currency risk is created by fluctuations in the fair values or cash flows of financial instruments due to changes in foreign exchange rates. A substantial portion of our activities are transacted in or referenced to US dollars including:
| · | sales of crude oil, natural gas and certain chemicals products; |
| · | capital spending and expenses for our oil and gas and chemicals operations; |
| · | commodity derivative contracts used primarily by our energy marketing group; and |
| · | short-term borrowings and long-term debt. |
In our oil and gas operations, we manage our exposure to fluctuations between the US and Canadian dollar by matching our expected net cash flows and borrowings in the same currency. Cash inflows generated by our foreign operations and borrowings on our US-dollar debt facilities are generally used to fund US-dollar capital expenditures and debt repayments. We maintain revolving Canadian and US-dollar borrowing facilities that can be used or repaid depending on expected net cash flows.
We designate most of our US-dollar borrowings as a hedge against our US-dollar net investment in self-sustaining foreign operations. The foreign exchange gains or losses related to the effective portion of our designated US-dollar debt are included in accumulated other comprehensive income in shareholders’ equity. Our net investment in self-sustaining foreign operations and our designated US-dollar debt at March 31, 2010 and December 31, 2009 are as follows:
(US$ millions) | March 31 2010 | December 31 2009 | ||||||
| Net Investment in Self-Sustaining Foreign Operations | 4,523 | 4,492 | ||||||
| Designated US-Dollar Debt | 4,523 | 4,492 | ||||||
For the three month period ended March 31, 2010, the ineffective portion of our US-dollar debt resulted in a net foreign exchange gain of $21 million ($19 million, net of income tax expense) and is included in marketing and other income. A one cent change in the US dollar to Canadian dollar exchange rate would increase or decrease our accumulated other comprehensive income by approximately $45 million, net of income tax, and would increase or decrease our net income by approximately $6 million, net of income tax.
We also have exposures to currencies other than the US dollar including a portion of our UK operating expenses, capital spending and future asset retirement obligations which are denominated in British Pounds and Euros. We do not have any material exposure to highly inflationary foreign currencies. In our energy marketing group, we enter into transactions in various currencies including Canadian and US dollars, British Pounds and Euros. We may actively manage significant currency exposures using forward contracts and swaps.
| (b) | Credit risk |
Credit risk affects our oil, gas and chemicals operations, and our trading and non-trading derivative activities, and is the risk of loss if counterparties do not fulfill their contractual obligations. Most of our credit exposure is with counterparties in the energy industry, including integrated oil companies, refiners and utilities, and are subject to normal industry credit risk. Approximately 70% of our exposure is with these large energy companies. This concentration of risk within the energy industry is reduced because of our broad base of domestic and international counterparties. Our processes to manage this risk are consistent with those in place at December 31, 2009.
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At March 31, 2010, only two counterparties individually made up more than 10% of our credit exposure. These counterparties are major integrated oil companies with a strong investment grade credit rating. No other counterparties made up more than 5% of our credit exposure. The following table illustrates the composition of credit exposure by credit rating.
Credit Rating | March 31 2010 | December 31 2009 |
| A or higher | 67% | 67% |
| BBB | 25% | 26% |
| Non-Investment Grade | 8% | 7% |
| Total | 100% | 100% |
Our maximum counterparty credit exposure at the balance sheet date consists primarily of the carrying amounts on non-derivative financial assets such as cash and cash equivalents, restricted cash, accounts receivable, as well as the fair value of derivative financial assets. We provided an allowance of $53 million for credit risk with our counterparties. In addition, we incorporate the credit risk associated with counterparty default, as well as Nexen’s own credit risk, into our estimates of fair value.
Collateral received from customers at March 31, 2010 includes $1 million of cash and $319 million of letters of credit. The cash received is included in accounts payable and accrued liabilities.
| (c) | Liquidity risk |
Liquidity risk is the risk that we will not be able to meet our financial obligations as they fall due. We require liquidity specifically to fund capital requirements, satisfy financial obligations as they come due, and to operate our energy marketing business. We generally rely on operating cash flows to provide liquidity and we also maintain significant undrawn committed credit facilities. At March 31, 2010, we had approximately $3.6 billion of cash and available committed lines of credit. This includes $2 billion of cash and cash equivalents on hand and undrawn term credit facilities of $1.6 billion, of which $391 million was supporting letters of credit at March 31, 2010. These facilities are available until 2012 unless extended. We also have about $466 million of undrawn, uncommitted credit facilities, of which $116 milli on was supporting letters of credit at March 31, 2010.
The following table details the contractual maturities for our non-derivative financial liabilities, including both the principal and interest cash flows at March 31, 2010:
| Total | < 1 Year | 1-3 Years | 4-5 Years | > 5 Years | ||||||||||||||||
| Long-Term Debt | 7,144 | – | 1,771 | 854 | 4,519 | |||||||||||||||
Interest on Long-Term Debt 1 | 7,724 | 350 | 700 | 658 | 6,016 | |||||||||||||||
| Total | 14,868 | 350 | 2,471 | 1,512 | 10,535 | |||||||||||||||
| 1 | Excludes interest on term credit facilities of $1.5 billion (US$1.5 billion) and Canexus term credit facilities of $247 million (US$244 million) as the amounts drawn on the facilities fluctuate. Based on amounts drawn at March 31, 2010 and existing variable interest rates, we would be required to pay $18 million per year until the outstanding amounts on the term credit facilities are repaid. |
The following table details contractual maturities for our derivative financial liabilities. The balance sheet amounts for derivative financial liabilities included below are not materially different from the contractual amounts due on maturity.
| Total | < 1 Year | 1-3 Years | 4-5 Years | > 5 Years | ||||||||||||||||
Trading Derivatives (Note 6) | 424 | 225 | 173 | 26 | – | |||||||||||||||
Non-Trading Derivatives (Note 6) | 20 | 20 | – | – | – | |||||||||||||||
| Total | 444 | 245 | 173 | 26 | – | |||||||||||||||
The commercial agreements our energy marketing group enter into often include financial assurance provisions that allow us and our counterparties to effectively manage credit risk. The agreements normally require collateral to be posted if an adverse credit-related event occurs, such as a drop in credit ratings to non-investment grade. Based on contracts in place and commodity prices at March 31, 2010, we could be required to post collateral of up to $1,016 million if we were downgraded to non-investment grade. These obligations
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are reflected on our balance sheet. The posting of collateral secures the payment of such amounts. In the event of a ratings downgrade, we have trading inventories and receivables that can be quickly monetized as well as undrawn credit facilities.
At March 31, 2010, collateral posted with counterparties includes $5 million of cash and $299 million of letters of credit related to our trading activities. Cash posted is included with our accounts receivable. Cash collateral is not normally applied to contract settlement. Once a contract has been settled, the collateral amounts are refunded. If there is a default, the cash is retained. Our exchange-traded derivative contracts are also subject to margin requirements. We have margin deposits of $178 million (December 31, 2009 – $198 million), which have been included in restricted cash.
| 8. | ACCOUNTS PAYABLE AND ACCRUED LIABILITIES |
March 31 2010 | December 31 2009 | |||||||
| Energy Marketing Payables | 1,422 | 1,366 | ||||||
Energy Marketing Derivative Contracts (Note 6) | 225 | 456 | ||||||
| Accrued Payables | 615 | 619 | ||||||
| Trade Payables | 245 | 210 | ||||||
| Income Taxes Payable | 233 | 179 | ||||||
| Stock-Based Compensation | 68 | 72 | ||||||
| Other | 276 | 136 | ||||||
| Total | 3,084 | 3,038 | ||||||
| 9. | SHORT-TERM BORROWINGS AND LONG-TERM DEBT |
March 31 2010 | December 31 2009 | |||||||
Canexus Term Credit Facilities, due 2012 (US$244 million drawn) (a) | 247 | 233 | ||||||
Term Credit Facilities, due 2012 (US$1.5 billion drawn) (b) | 1,523 | 1,570 | ||||||
| Canexus Notes, due 2013 (US$50 million) | 51 | 52 | ||||||
| Notes, due 2013 (US$500 million) | 508 | 523 | ||||||
| Canexus Convertible Debentures, due 2014 | 41 | 46 | ||||||
| Notes, due 2015 (US$250 million) | 254 | 262 | ||||||
| Notes, due 2017 (US$250 million) | 254 | 262 | ||||||
| Notes, due 2019 (US$300 million) | 305 | 314 | ||||||
| Notes, due 2028 (US$200 million) | 203 | 209 | ||||||
| Notes, due 2032 (US$500 million) | 508 | 523 | ||||||
| Notes, due 2035 (US$790 million) | 802 | 827 | ||||||
| Notes, due 2037 (US$1,250 million) | 1,270 | 1,308 | ||||||
| Notes, due 2039 (US$700 million) | 711 | 733 | ||||||
| Subordinated Debentures, due 2043 (US$460 million) | 467 | 481 | ||||||
| 7,144 | 7,343 | |||||||
| Unamortized Debt Issue Costs | (90 | ) | (92 | ) | ||||
| Total | 7,054 | 7,251 | ||||||
| (a) | Canexus term credit facilities |
Canexus has $450 million (US$444 million) of committed, secured term credit facilities available until 2012. At March 31, 2010, $247 million (US$244 million) was drawn on these facilities (December 31, 2009 – $233 million (US$223 million)). Borrowings are available as Canadian bankers’ acceptances, LIBOR-based loans, Canadian prime rate loans or US-dollar base rate loans. Interest is payable monthly at floating rates. The term credit facilities are secured by a floating charge debenture over all of Canexus’ assets. The credit facility also contains covenants with respect to certain financial ratios of Canexus. The weighted-average interest rate on the Canexus term credit facilities was 1.5% for the three months ended March 31, 2010 (three months ended March 31, 2009 – 2.7%).
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| (b) | Term credit facilities |
We have unsecured term credit facilities of $3.1 billion (US$3.1 billion) available until 2012. At March 31, 2010, $1.5 billion (US$1.5 billion) was drawn on these facilities (December 31, 2009 – $1.6 billion (US$1.5 billion)). Borrowings are available as Canadian bankers’ acceptances, LIBOR-based loans, Canadian prime rate loans, US-dollar base rate loans or British pound call-rate loans. Interest is payable at floating rates. The weighted-average interest rate on our term credit facilities was 0.9% for the three months ended March 31, 2010 (three months ended March 31, 2009 – 1.1%). At March 31, 2010, $391 million (US$385 million) of these facilities were utilized to support outstanding letters of credit (December 31, 2009 – $407 million (US$389 million)).
| (c) | Interest expense |
| Three Months Ended March 31 | ||||||||
| 2010 | 2009 | |||||||
| Long-Term Debt | 94 | 89 | ||||||
| Other | 4 | 5 | ||||||
| Total | 98 | 94 | ||||||
Less: Capitalized | (18 | ) | (26 | ) | ||||
| Total | 80 | 68 | ||||||
Capitalized interest relates to and is included as part of the cost of our oil and gas properties. The capitalization rates are based on our weighted-average cost of borrowings.
| (d) | Short-term borrowings |
Nexen has uncommitted, unsecured credit facilities of approximately $466 million (US$459 million), none of which were drawn at March 31, 2010 (December 31, 2009 – nil). We utilized $116 million (US$114 million) of these facilities to support outstanding letters of credit at March 31, 2010 (December 31, 2009 – $86 million (US$82 million)). Interest is payable at floating rates.
| 10. | CAPITAL MANAGEMENT |
Our objectives and processes for managing our capital structure are consistent with those in place at December 31, 2009. Our capital consists of equity, short-term borrowings, long-term debt and cash and cash equivalents as follows:
March 31 2010 | December 31 2009 | |||||||
Net Debt 1 | ||||||||
Long-Term Debt | 7,054 | 7,251 | ||||||
Less: Cash and Cash Equivalents | (1,997 | ) | (1,700 | ) | ||||
| Total | 5,057 | 5,551 | ||||||
Equity 2 | 7,827 | 7,646 | ||||||
1 Includes all of our borrowings and is calculated as long-term debt and short-term borrowings less cash and cash equivalents.
2 Equity is the historical issue of equity and accumulated retained earnings.
We monitor the leverage in our capital structure by reviewing the ratio of net debt to adjusted cash flow (cash flow from operating activities before changes in non-cash working capital and other) and interest coverage ratios at various commodity prices. Net debt and adjusted cash flow are non-GAAP measures that are unlikely to be comparable to similar measures presented by others. We calculate net debt using the GAAP measures of long-term debt and short-term borrowings less cash and cash equivalents (excluding restricted cash).
We use the ratio of net debt to adjusted cash flow as a key indicator of our leverage and to monitor the strength of our balance sheet. For the twelve months ended March 31, 2010, the net debt to adjusted cash flow was 2.2 times compared to 2.5 times at December 31, 2009. While we typically expect the target ratio to fluctuate between 1.0 and 2.0 times under normalized commodity prices, this can be higher or lower depending on commodity price volatility, when we are in the investment cycle, or when we identify strategic opportunities requiring additional investment. Whenever we exceed our target ratio, we assess whether we need to develop a strategy to reduce our leverage and lower this ratio back to target levels over time.
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Our interest coverage ratio monitors our ability to fund the interest requirements associated with our debt. Our interest coverage increased from 8.5 times at the end of 2009 to 8.9 times at March 31, 2010. Interest coverage is calculated by dividing our adjusted EBITDA by interest expense before capitalized interest. Adjusted EBITDA is a non-GAAP measure that is calculated using net income excluding interest expense, provision for income taxes, exploration expenses, DD&A, impairment and other non-cash expenses. The calculation of adjusted EBITDA is set out in the following table and is unlikely to be comparable to similar measures presented by others.
| Three Months Ended March 31 2010 | Year Ended December 31 2009 | |||||||
| Net Income Attributable to Nexen Inc. | 586 | 536 | ||||||
Add: | ||||||||
Interest Expense | 324 | 312 | ||||||
Provision for Income Taxes | 388 | 260 | ||||||
Depreciation, Depletion, Amortization and Impairment | 1,781 | 1,802 | ||||||
Exploration Expense | 342 | 302 | ||||||
Recovery of Non-Cash Stock-Based Compensation | (11 | ) | (10 | ) | ||||
Change in Fair Value of Crude Oil Put Options | 251 | 251 | ||||||
Other Non-Cash Expenses | (153 | ) | (136 | ) | ||||
| Adjusted EBITDA | 3,508 | 3,317 | ||||||
| 11. | ASSET RETIREMENT OBLIGATIONS |
Changes in carrying amounts of the asset retirement obligations associated with our Property, Plant & Equipment (PP&E) are as follows:
| Three Months Ended March 31 2010 | Year Ended December 31 2009 | |||||||
| Balance at Beginning of Period | 1,053 | 1,059 | ||||||
Obligations Incurred with Development Activities | 7 | 27 | ||||||
Obligations Settled | (11 | ) | (42 | ) | ||||
Accretion Expense | 17 | 70 | ||||||
Revisions to Estimates | (32 | ) | 13 | |||||
Effects of Changes in Foreign Exchange Rate | (38 | ) | (74 | ) | ||||
Balance at End of Period 1, 2 | 996 | 1,053 | ||||||
| 1 | Obligations due within 12 months of $64 million (December 31, 2009 – $35 million) have been included in accounts payable and accrued liabilities. |
| 2 | Obligations relating to our oil and gas activities amount to $962 million (December 31, 2009 – $1,002 million) and obligations relating to our chemicals business amount to $34 million (December 31, 2009 – $51 million). |
Our total estimated undiscounted inflated asset retirement obligations amount to $2,261 million (December 31, 2009 – $2,341 million). We discounted the total estimated asset retirement obligations using a weighted-average, credit-adjusted, risk-free rate of 5.9%. Approximately $298 million included in our asset retirement obligations is expected to be settled over the next five years. The remaining obligations settle beyond five years and are expected to be funded by future cash flows from our operations.
| 12. | DEFERRED CREDITS AND OTHER LIABILITIES |
March 31 2010 | December 31 2009 | |||||||
| Deferred Tax Credit | 460 | 503 | ||||||
Long-Term Energy Marketing Derivative Contracts (Note 6) | 199 | 212 | ||||||
| Defined Benefit Pension Obligations | 75 | 76 | ||||||
| Capital Lease Obligations | 60 | 61 | ||||||
| Deferred Transportation Revenue | 52 | 55 | ||||||
| Other | 113 | 114 | ||||||
| Total | 959 | 1,021 | ||||||
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13. | SHAREHOLDERS’ EQUITY |
Dividends
Dividends per common share for the three months ended March 31, 2010 were $0.05 per common share (2009 – $0.05). Dividends paid to holders of common shares have been designated as “eligible dividends” for Canadian tax purposes.
| 14. | MARKETING AND OTHER INCOME |
| Three Months Ended March 31 | ||||||||
| 2010 | 2009 | |||||||
| Marketing Revenue, Net | 86 | 267 | ||||||
| Long Lake Purchased Bitumen Sales | 28 | – | ||||||
| Change in Fair Value of Crude Oil Put Options | (16 | ) | (16 | ) | ||||
| Interest | 4 | 2 | ||||||
| Foreign Exchange Gains | 34 | 19 | ||||||
| Other | 15 | (15 | ) | |||||
| Total | 151 | 257 | ||||||
| 15. | EARNINGS PER COMMON SHARE |
We calculate basic earnings per common share using net income divided by the weighted-average number of common shares outstanding. We calculate diluted earnings per common share in the same manner as basic, except we use the weighted-average number of diluted common shares outstanding in the denominator.
| Three Months Ended March 31 | ||||||||
| (millions of shares) | 2010 | 2009 | ||||||
| Weighted-average number of common shares outstanding | 523.6 | 520.2 | ||||||
| Shares issuable pursuant to tandem options | 6.3 | 7.6 | ||||||
| Shares notionally purchased from proceeds of tandem options | (4.8 | ) | (5.1 | ) | ||||
| Weighted-average number of diluted common shares outstanding | 525.1 | 522.7 | ||||||
In calculating the weighted-average number of diluted common shares outstanding for the three months ended March 31, 2010, we excluded 16,476,455 tandem options, because their exercise price was greater than the average common share market price in the period. In calculating the weighted-average number of diluted common shares outstanding for the three months ended March 31, 2009, we excluded 4,103,560 tandem options, because their exercise price was greater than the average common share market price in the period. During the periods presented, outstanding tandem options were the only potential dilutive instruments.
| 16. | COMMITMENTS, CONTINGENCIES AND GUARANTEES |
As described in Note 15 to the Audited Consolidated Financial Statements included in our 2009 Form 10-K, there are a number of lawsuits and claims pending, the ultimate results of which cannot be ascertained at this time. We record costs as they are incurred or become determinable. We continue to believe the resolution of these matters would not have a material adverse effect on our liquidity, consolidated financial position or results of operations.
During the quarter, we sold our European gas and power marketing business. We agreed to maintain our parental guarantees to the existing counterparties until the purchaser is able to replace them. They expire at the earlier of the purchaser replacing the guarantees and July 25, 2010. We are obligated to perform under the guarantees only if the purchaser does not meet its obligations to the counterparties. Our total exposure is $275 million for which the purchaser has provided us with an indemnity and a letter of credit from a highly rated financial institution.
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| 17. | CASH FLOWS |
| (a) | Charges and credits to income not involving cash |
| Three Months Ended March 31 | ||||||||
| 2010 | 2009 | |||||||
| Depreciation, Depletion, Amortization and Impairment | 388 | 409 | ||||||
| Stock-Based Compensation | (1 | ) | – | |||||
| Loss (Gains) on Disposition of Assets | 3 | (7 | ) | |||||
| Recovery of Future Income Taxes | (100 | ) | (87 | ) | ||||
| Change in Fair Value of Crude Oil Put Options | 16 | 16 | ||||||
| Foreign Exchange | (41 | ) | (13 | ) | ||||
| Other | – | 1 | ||||||
| Total | 265 | 319 | ||||||
| (b) | Changes in non-cash working capital |
| Three Months Ended March 31 | ||||||||
| 2010 | 2009 | |||||||
Accounts Receivable | (218 | ) | 298 | |||||
Inventories and Supplies | 113 | (49 | ) | |||||
Other Current Assets | 73 | (8 | ) | |||||
Accounts Payable and Accrued Liabilities | 385 | 185 | ||||||
Other Current Liabilities | (9 | ) | 13 | |||||
| Total | 344 | 439 | ||||||
| Relating to: | �� | |||||||
Operating Activities | 256 | 420 | ||||||
Investing Activities | 88 | 19 | ||||||
| Total | 344 | 439 | ||||||
| (c) | Other cash flow information |
| Three Months Ended March 31 | ||||||||
| 2010 | 2009 | |||||||
| Interest Paid | 103 | 81 | ||||||
| Income Taxes Paid | 207 | 34 | ||||||
Cash flow from other operating activities includes cash outflows related to geological and geophysical expenditures of $12 million for the three months ended March 31, 2010 (2009 – $12 million).
| 18. | SUBSEQUENT EVENTS |
In April 2010, we substantially completed negotiations for the sale of our North American natural gas business subject to finalizing documentation and customary closing conditions. We expect to sign the agreement in the second quarter and close the sale in the third quarter. The sale is expected to be cash neutral and we expect to recognize a non-cash loss on the sale of between $250 and $290 million. This loss primarily relates to the transfer of long-term natural gas physical transportation commitments that are less valuable with increased gas supplies that reduce the need for transport services. Although volatile on a quarterly basis, we have had success with our marketing business over the last 10 years generating about $800 million of positive cash flow.
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| 19. | OPERATING SEGMENTS AND RELATED INFORMATION |
Nexen is involved in activities relating to Oil and Gas, Energy Marketing and Chemicals in various geographic locations as described in Note 20 to the Audited Consolidated Financial Statements included in our 2009 Form 10-K.
Three months ended March 31, 2010
| Oil and Gas | Energy Marketing | Chemicals | Corporate and Other | Total | ||||||||||||||||||||||||||||||||||||
| United Kingdom | Canada | Syncrude | United States | Yemen | Other Countries | 1 | ||||||||||||||||||||||||||||||||||
| Net Sales | 755 | 180 | 134 | 113 | 182 | 15 | 9 | 113 | – | 1,501 | ||||||||||||||||||||||||||||||
| Marketing and Other | 5 | 28 | 1 | – | 5 | – | 83 | 7 | 22 | 2 | 151 | |||||||||||||||||||||||||||||
| Total Revenues | 760 | 208 | 135 | 113 | 187 | 15 | 92 | 120 | 22 | 1,652 | ||||||||||||||||||||||||||||||
| Less: Expenses | ||||||||||||||||||||||||||||||||||||||||
Operating | 77 | 134 | 67 | 22 | �� | 41 | 1 | 10 | 70 | – | 422 | |||||||||||||||||||||||||||||
Depreciation, Depletion, Amortization and Impairment | 168 | 80 | 13 | 64 | 35 | 2 | 5 | 11 | 10 | 388 | ||||||||||||||||||||||||||||||
Transportation and Other | (1 | ) | 56 | 7 | 2 | 3 | – | 123 | 12 | – | 202 | |||||||||||||||||||||||||||||
General and Administrative 3 | 13 | 16 | – | 11 | 1 | 8 | 21 | 8 | 40 | 118 | ||||||||||||||||||||||||||||||
Exploration | 24 | 7 | – | 16 | – | 46 | 4 | – | – | – | 93 | |||||||||||||||||||||||||||||
Interest | – | – | – | – | – | – | – | 1 | 79 | 80 | ||||||||||||||||||||||||||||||
Income (Loss) before Income Taxes | 479 | (85 | ) | 48 | (2 | ) | 107 | (42 | ) | (67 | ) | 18 | (107 | ) | 349 | |||||||||||||||||||||||||
Less: Provision for (Recovery of) Income Taxes | 240 | (21 | ) | 12 | (1 | ) | 37 | (38 | ) | (23 | ) | 4 | (51 | ) | 159 | |||||||||||||||||||||||||
Less: Non-Controlling Interests | – | – | – | – | – | – | – | 5 | – | 5 | ||||||||||||||||||||||||||||||
| Net Income (Loss) | 239 | (64 | ) | 36 | (1 | ) | 70 | (4 | ) | (44 | ) | 9 | (56 | ) | 185 | |||||||||||||||||||||||||
| Identifiable Assets | 4,696 | 7,848 | 5 | 1,292 | 1,717 | 257 | 1,141 | 2,588 | 6 | 701 | 2,523 | 22,763 | ||||||||||||||||||||||||||||
| Capital Expenditures | ||||||||||||||||||||||||||||||||||||||||
Development and Other | 88 | 70 | 19 | 15 | 10 | 91 | 9 | 49 | 6 | 357 | ||||||||||||||||||||||||||||||
Exploration | 41 | 68 | – | 49 | – | 41 | – | – | – | 199 | ||||||||||||||||||||||||||||||
| Total | 129 | 138 | 19 | 64 | 10 | 132 | 9 | 49 | 6 | 556 | ||||||||||||||||||||||||||||||
| Property, Plant and Equipment | ||||||||||||||||||||||||||||||||||||||||
Cost | 6,027 | 9,781 | 1,482 | 3,828 | 2,397 | 991 | 265 | 1,164 | 377 | 26,312 | ||||||||||||||||||||||||||||||
Less: Accumulated DD&A | 2,745 | 2,108 | 281 | 2,504 | 2,286 | 97 | 88 | 570 | 252 | 10,931 | ||||||||||||||||||||||||||||||
| Net Book Value | 3,282 | 7,673 | 5 | 1,201 | 1,324 | 111 | 894 | 177 | 594 | 125 | 15,381 | |||||||||||||||||||||||||||||
1 Includes results of operations from producing activities in Colombia.
2 Includes interest income of $4 million, foreign exchange gains of $34 million and a decrease in the fair value of crude oil put options of $16 million.
3 Includes stock-based compensation expense of $2 million.
4 Includes exploration activities primarily in Nigeria, Norway and Colombia.
5 Includes costs of $6,088 million related to our insitu oil sands (Long Lake and future phases).
6 Approximately 79% of Marketing’s identifiable assets are accounts receivable and inventories.
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Three months ended March 31, 2009
| Oil and Gas | Energy Marketing | Chemicals | Corporate and Other | Total | ||||||||||||||||||||||||||||||||||||
United Kingdom | Canada | Syncrude | United States | Yemen | Other Countries | 1 | ||||||||||||||||||||||||||||||||||
| Net Sales | 478 | 91 | 98 | 63 | 162 | 19 | 13 | 124 | – | 1,048 | ||||||||||||||||||||||||||||||
| Marketing and Other | 4 | 7 | – | – | 3 | – | 267 | (14 | ) | (10 | ) 2 | 257 | ||||||||||||||||||||||||||||
| Total Revenues | 482 | 98 | 98 | 63 | 165 | 19 | 280 | 110 | (10 | ) | 1,305 | |||||||||||||||||||||||||||||
| Less: Expenses | ||||||||||||||||||||||||||||||||||||||||
Operating | 51 | 41 | 66 | 23 | 47 | 2 | 8 | 67 | – | 305 | ||||||||||||||||||||||||||||||
Depreciation, Depletion, Amortization and Impairment | 193 | 63 | 11 | 68 | 41 | 5 | 4 | 12 | 12 | 409 | ||||||||||||||||||||||||||||||
Transportation and Other | (3 | ) | 3 | 7 | 13 | 3 | – | 162 | 10 | 6 | 201 | |||||||||||||||||||||||||||||
General and Administrative | 2 | 14 | – | 14 | 4 | 8 | 23 | 9 | 26 | 100 | ||||||||||||||||||||||||||||||
Exploration | 8 | 21 | – | 10 | – | 14 | 3 | – | – | – | 53 | |||||||||||||||||||||||||||||
Interest | – | – | – | – | – | – | – | 2 | 66 | 68 | ||||||||||||||||||||||||||||||
Income (Loss) before Income Taxes | 231 | (44 | ) | 14 | (65 | ) | 70 | (10 | ) | 83 | 10 | (120 | ) | 169 | ||||||||||||||||||||||||||
Less: Provision for (Recovery of) Income Taxes | 86 | (11 | ) | 4 | (23 | ) | 24 | (6 | ) | 35 | 2 | (80 | ) | 31 | ||||||||||||||||||||||||||
Less: Non-Controlling Interests | – | – | – | – | – | – | – | 3 | – | 3 | ||||||||||||||||||||||||||||||
| Net Income (Loss) | 145 | (33 | ) | 10 | (42 | ) | 46 | (4 | ) | 48 | 5 | (40 | ) | 135 | ||||||||||||||||||||||||||
| Identifiable Assets | 6,403 | 7,678 | 4 | 1,212 | 2,100 | 400 | 807 | 3,035 | 5 | 594 | 1,390 | 23,619 | ||||||||||||||||||||||||||||
| Capital Expenditures | ||||||||||||||||||||||||||||||||||||||||
Development and Other | 149 | 244 | 17 | 42 | 29 | 58 | 8 | 36 | 1 | 584 | ||||||||||||||||||||||||||||||
Exploration | 28 | 94 | – | 26 | – | 15 | – | – | – | 163 | ||||||||||||||||||||||||||||||
Proved Property Acquisitions | – | 757 | – | – | – | – | – | – | – | 757 | ||||||||||||||||||||||||||||||
| Total | 177 | 1,095 | 17 | 68 | 29 | 73 | 8 | 36 | 1 | 1,504 | ||||||||||||||||||||||||||||||
| Property, Plant and Equipment | ||||||||||||||||||||||||||||||||||||||||
Cost | 6,869 | 9,225 | 1,386 | 4,591 | 2,920 | 636 | 256 | 983 | 332 | 27,198 | ||||||||||||||||||||||||||||||
Less: Accumulated DD&A | 2,419 | 1,843 | 244 | 2,850 | 2,729 | 121 | 80 | 523 | 212 | 11,021 | ||||||||||||||||||||||||||||||
| Net Book Value | 4,450 | 7,382 | 4 | 1,142 | 1,741 | 191 | 515 | 176 | 460 | 120 | 16,177 | |||||||||||||||||||||||||||||
| 1 | Includes results of operations from producing activities in Colombia. |
| 2 | Includes interest income of $2 million, foreign exchange gains of $19 million, decrease in the fair value of crude oil put options of $16 million and other losses of $15 million. |
| 3 | Includes exploration activities primarily in Norway and Colombia. |
| 4 | Includes costs of $5,658 million related to our insitu oil sands (Long Lake and future phases). |
| 5 | Approximately 77% of Marketing’s identifiable assets are accounts receivable and inventories. |
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| 20. | DIFFERENCES BETWEEN CANADIAN AND US GENERALLY ACCEPTED ACCOUNTING PRINCIPLES |
The Unaudited Consolidated Financial Statements have been prepared in accordance with Canadian GAAP. The US GAAP Unaudited Consolidated Statements and summaries of differences from Canadian GAAP are as follows:
Unaudited Consolidated Statement of Income – US GAAP
For the Three Months Ended March 31
| (Cdn$ millions, except per share amounts) | 2010 | 2009 | ||||||
| Revenues and Other Income | ||||||||
Net Sales | 1,501 | 1,048 | ||||||
Marketing and Other (v); (vi) | 205 | 292 | ||||||
| 1,706 | 1,340 | |||||||
| Expenses | ||||||||
Operating | 422 | 305 | ||||||
Depreciation, Depletion, Amortization and Impairment | 388 | 409 | ||||||
Transportation and Other (v) | 205 | 194 | ||||||
General and Administrative (iv) | 126 | 108 | ||||||
Exploration | 93 | 53 | ||||||
Interest | 80 | 68 | ||||||
| 1,314 | 1,137 | |||||||
| Income before Provision for Income Taxes | 392 | 203 | ||||||
| Provision for (Recovery of) Income Taxes | ||||||||
Current | 259 | 118 | ||||||
Deferred (iv); (vi); (vii) | (86 | ) | (74 | ) | ||||
| 173 | 44 | |||||||
| Net Income – US GAAP | 219 | 159 | ||||||
Less: Net Income Attributable to Non-Controlling Interests | 5 | 3 | ||||||
Net Income Attributable to Nexen Inc. – US GAAP 1 | 214 | 156 | ||||||
Earnings Per Common Share ($/share) (Note 15) | ||||||||
Basic | 0.41 | 0.30 | ||||||
Diluted | 0.41 | 0.30 | ||||||
1 Reconciliation of Canadian and US GAAP Net Income
Three Months Ended March 31 | ||||||||
| 2010 | 2009 | |||||||
| Net Income Attributable to Nexen Inc – Canadian GAAP | 185 | 135 | ||||||
| Impact of US Principles, Net of Income Taxes: | ||||||||
Stock-based Compensation (iv) | (6 | ) | – | |||||
Inventory Valuation (vi) | 35 | (6 | ) | |||||
Deferred Taxes (vii) | – | 27 | ||||||
| Net Income Attributable to Nexen Inc – US GAAP | 214 | 156 | ||||||
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Unaudited Consolidated Balance Sheet – US GAAP
| March 31 | December 31 | |||||||
| (Cdn$ millions, except share amounts) | 2010 | 2009 | ||||||
| Assets | ||||||||
Current Assets | ||||||||
Cash and Cash Equivalents | 1,997 | 1,700 | ||||||
Restricted Cash | 178 | 198 | ||||||
Accounts Receivable | 2,635 | 2,788 | ||||||
Inventories and Supplies (vi) | 555 | 610 | ||||||
Other | 102 | 185 | ||||||
Total Current Assets | 5,467 | 5,481 | ||||||
Property, Plant and Equipment | ||||||||
Net of Accumulated Depreciation, Depletion, Amortization and Impairment of $11,324 (December 31, 2009 - $11,200) (i); (iii) | 15,332 | 15,443 | ||||||
Goodwill | 330 | 339 | ||||||
Deferred Income Tax Assets | 1,238 | 1,148 | ||||||
Deferred Charges and Other Assets | 328 | 370 | ||||||
| Total Assets | 22,695 | 22,781 | ||||||
| Liabilities | ||||||||
Current Liabilities | ||||||||
Accounts Payable and Accrued Liabilities (iv) | 3,185 | 3,131 | ||||||
Accrued Interest Payable | 77 | 89 | ||||||
Dividends Payable | 26 | 26 | ||||||
Total Current Liabilities | 3,288 | 3,246 | ||||||
Long-Term Debt | 7,054 | 7,251 | ||||||
Deferred Income Tax Liabilities (i); (ii); (iv); (vi); (vii) | 2,727 | 2,720 | ||||||
Asset Retirement Obligations | 932 | 1,018 | ||||||
Deferred Credits and Other Liabilities (ii) | 1,064 | 1,126 | ||||||
| Equity | ||||||||
Nexen Inc. Shareholders’ Equity | ||||||||
Common Shares, no par value | ||||||||
Authorized:Unlimited | ||||||||
Outstanding:2010 – 524,046,867 shares | ||||||||
2009 – 522,915,843 shares | 1,076 | 1,049 | ||||||
Contributed Surplus | – | 1 | ||||||
Retained Earnings (i); (ii); (iv); (vi); (vii) | 6,763 | 6,575 | ||||||
Accumulated Other Comprehensive Loss (ii) | (280 | ) | (269 | ) | ||||
Total Nexen Inc. Shareholders’ Equity | 7,559 | 7,356 | ||||||
Canexus Non-Controlling Interests | 71 | 64 | ||||||
Total Equity | 7,630 | 7,420 | ||||||
Commitments, Contingencies and Guarantees (Note 16) | ||||||||
| Total Liabilities and Equity | 22,695 | 22,781 | ||||||
Unaudited Consolidated Statement of Comprehensive Income – US GAAP
For the Three Months Ended March 31
| Three Months Ended March 31 | ||||||||
| 2010 | 2009 | |||||||
| Net Income Attributable to Nexen Inc. – US GAAP | 214 | 156 | ||||||
| Other Comprehensive Income (Loss), Net of Income Taxes: | ||||||||
Foreign Currency Translation Adjustment | (11 | ) | 6 | |||||
| Comprehensive Income Attributable to Nexen Inc. – US GAAP | 203 | 162 | ||||||
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Unaudited Consolidated Statement of Accumulated Other Comprehensive Loss – US GAAP
| March 31 | December 31 | |||||||
| 2010 | 2009 | |||||||
| Foreign Currency Translation Adjustment | (201 | ) | (190 | ) | ||||
Unamortized Defined Benefit Pension Plan Costs (ii) | (79 | ) | (79 | ) | ||||
| Accumulated Other Comprehensive Loss | (280 | ) | (269 | ) | ||||
Notes to the Unaudited Consolidated US GAAP Financial Statements:
| i. | Under Canadian GAAP, we defer certain development costs to PP&E. Under US principles, these costs have been included in operating expenses in prior years. As a result, PP&E is lower under US GAAP by $30 million (December 31, 2009 – $30 million) and deferred income tax liabilities are lower by $11 million (December 31, 2009 – $11 million). |
| ii. | US GAAP requires the recognition of the over-funded and under-funded status of a defined benefit plan on the balance sheet as an asset or liability. At March 31, 2010 and December 31, 2009, the unfunded amount of our defined benefit pension plans that was not included in the pension liability under Canadian GAAP was $105 million. This amount has been included in deferred credits and other liabilities and $79 million, net of income taxes, has been included in Accumulated Other Comprehensive Income (AOCI). |
| iii. | On January 1, 2003, we adopted Accounting for Asset Retirement Obligations for US GAAP reporting purposes. We adopted the equivalent Canadian standard for asset retirement obligations on January 1, 2004. These standards are consistent except for the adoption date which results in our PP&E under US GAAP being lower by $19 million. |
| iv. | Under Canadian principles, we record obligations for liability-based stock compensation plans using the intrinsic-value method of accounting. Under US principles, obligations for liability-based stock compensation plans are recorded using the fair-value method of accounting. In addition, under Canadian principles, we retroactively adopted EIC-162 which requires the accelerated recognition of stock-based compensation expense for all stock-based awards made to our retired and retirement-eligible employees. However, US GAAP requires the accelerated recognition of stock-based compensation expense for such employees for awards granted on or after January 1, 2006. As a result under US GAAP: |
| · | general and administrative (G&A) expense is higher by $8 million, ($6 million, net of income taxes), for the three months ended March 31, 2010, (2009 – higher by $8 million ($6 million, net of income taxes)); and |
| · | accounts payable and accrued liabilities are higher by $101 million as at March 31, 2010 (December 31, 2009 – $93 million). |
| v. | Under US GAAP, asset disposition gains and losses are included with transportation and other expense. Losses of $3 million for the three months ended March 31, 2010, were reclassified from marketing and other income to transportation and other expense (gains of $7 million were reclassified for the three months ended March 31, 2009). |
| vi. | Under Canadian GAAP, we carry our commodity inventory held for trading purposes at fair value, less any costs to sell. Under US GAAP, we are required to carry this inventory at the lower of cost or net realizable value. As a result: |
| · | marketing and other income is higher by $51 million ($35 million, net of income taxes) for the three months ended March 31, 2010 (2009 – higher by $42 million ($27 million, net of income taxes)); and |
| · | inventories are lower by $19 million as at March 31, 2010 (December 31, 2009 – lower by $70 million) and deferred income tax liabilities are $7 million lower (December 31, 2009 – lower by $23 million). |
| vii. | Under US GAAP, we are required to apply FIN48 Accounting for Uncertainty in Income Taxes regarding accounting and disclosure for uncertain tax positions. |
As at March 31, 2010, the total amount of our unrecognized tax benefit was approximately $279 million, all of which, if recognized, would affect our effective tax rate. To the extent interest and
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penalties may be assessed by taxing authorities on any underpayment of income tax, such amounts have been accrued and are classified as a component of income taxes in the Unaudited Consolidated Statement of Income. As at March 31, 2010, the total amount of interest and penalties related to uncertain tax positions recognized in deferred income tax liabilities in the US GAAP – Unaudited Consolidated Balance Sheet was approximately $8 million. We had no interest or penalties included in the US GAAP – Unaudited Consolidated Statement of Income for the three months ended March 31, 2010.
Our income tax filings are subject to audit by taxation authorities and as at March 31, 2010 the following tax years remained subject to examination, (i) Canada – 1985 to date (ii) United Kingdom – 2008 to date and (iii) United States – 2005 to date. We do not anticipate any material changes to the unrecognized tax benefits previously disclosed within the next 12 months.
New Accounting Pronouncements – US GAAP
In January 2010, the Financial Accounting Standards Board issued guidance to improve fair value measurement disclosures. The guidance requires entities to describe transfers between the three levels of the fair value hierarchy and present items separately in the level 3 reconciliation. This guidance is consistent with fair value measurement disclosures adopted for Canadian GAAP in 2009. Adoption of this guidance did not have an impact on our results of operations or financial position.
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